ML051230417

Submittal of Licensee Annual Financial Report

ML051230417
Person / Time
Site:	Harris, Brunswick, Robinson, 07200003
Issue date:	04/27/2005
From:	Burton C Progress Energy Carolinas
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
PE&RAS05-025
Download: ML051230417 (118)

Text

10 CFR 50.71 (b), 10 CFR 72.80(b) 8$ Progress Energy PO Box 1551 411 Fayetteville Street Mall Raleigh NC 27602 PE&RAS05-025 April 27, 2005 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555-0001 U.S. Nuclear Regulatory Commission Director, Spent Fuel Project Office Office of Nuclear Material Safety and Safeguards Attention: Document Control Desk Washington, DC 20555-0001 BRUNSWICK STEAM ELECTRIC PLANT, UNIT NOS. 1 AND 2 DOCKET NOS. 50-325 AND 50-324 / LICENSE NOS. DPR-71 AND DPR-62 SHEARON HARRIS NUCLEAR POWER PLANT, UNIT NO. 1 DOCKET NO. 50-400 / LICENSE NO. NPF-63 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 DOCKET NO. 50-261 /LICENSE NO. DPR-23 H. B. ROBINSON STEAM ELECTRIC PLANT, UNIT NO. 2 INDEPENDENT SPENT FUEL STORAGE INSTALLATION DOCKET NO. 72-3 / LICENSE NO. SNM-2502 Submittal of Licensee Annual Financial Report Ladies and Gentlemen:

In accordance with 10 CFR 50.7 1(b) and 10 CFR 72.80(b), Carolina Power & Light Company doing business as Progress Energy Carolinas, Inc. (PEC) submits the enclosed Annual Report, including certified financial statements.

No new commitments have been made in this submittal. If you have questions, please notify Tony Groblewvski at (919) 546-4579.

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United States Nuclear Regulatory Commission PE&RAS05-025 Page 2 Sincerely, Chris Burton Manager, Performance Evaluation &

Regulatory Affairs RTG

Enclosure:

Progress Energy 2004 Annual Report c: W. D. Travers, USNRC Regional Administrator - Region II USNRC Senior Resident Inspector - BSEP, Unit Nos. I and 2 B. L. Mozafari, NRR Project Manager - BSEP, Unit Nos. 1 and 2 USNRC Senior Resident Inspector - HNP, Unit No. I C. P. Patel, NRR Project Manager - HNP, Unit No. 1, HBRSEP, Unit No. 2 USNRC Senior Resident Inspector - HBRSEP, Unit No. 2 J. Sanford, North Carolina Utilities Commission Geneva Thigpen, Chief Clerk, North Carolina Utilities Commission Sam Watson, Staff Attorney, North Carolina Utilities Commission

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-,.-i,.h..s It's focus. And at Progress Energy, it keeps our sights set on balanced long-term performance. It's:about having a sound strategyfor the futureel as steady execution today.its promoting successful economic development to: create tomorrow's oppor-tunities. And it's investing in communityt initiatives that make our territory a more attractive, more to., .0 , .es u; healthy place to live. Our focus motivates us to-look-past what's obvious- and into whats possible. And it's why we're confidentin our vision for the future.

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Dear Fellow Shareholders:

Progress Energy kept a relentless focus on excellence and long-term value in 2004. We increased the dividend for the 17th consecutive year and for the 29th time in the last 30 years. And we entered 2005 with a clear vision of what we 'need to accomplish and awell-founded confidence in our ability to do it. '

Even though the unprecedented series of hurricanes last year created serious problems for our customers and company in the short run, the' fundamentals of our core business remain sound.

Moreover, our employees once again proved how well they rise to any challenge.

Executing a Clear Strategic Plan- In2004, our management team conducted an extensive analysis of our industry and our company. We developed a clear road map for the next three years and beyond that will reinforce our position as a buy-and-hold stock providing good value at modest risk.

We reaffirmed the basic strategic focus on our three core energy businesses: Progress Energy Carolinas and Progress Energy Florida - our electric utilities serving regulated markets -

and Progress Ventures (excluding synthetic fuels), which serves competitive energy markets inthe eastern United States.

Our strategic plan also includes selective asset sales to complete the restoration of our balance sheet. We sold our North Texas natural gas properties in December 2004 and have used the over $250 million in proceeds to retire debt. In February 2005, we reached adefinitive agree-,

ment to sell Progress Rail, a subsidiary acquired Inthe 2000 merger. The $405 million in proceeds also will be used for debt reduction.,

In addition, our plan calls for growing our core-business earnings per share over the long term by 3 percent to 5 percent a year, which will support continued'dividend growth. We know that consistent dividend growth is a major reason investors buy our stock.

Our strategy will help us maintain and enhance shareholder value as we make the transition beyond the federal synthetic-fuel tax program that expires at the end of 2007. In 2004, we resolved the federal tax audit issues with our Colona synthetic-fuel facilities, but, as of early 2005, we are still working with the Internal Revenue Service to resolve issues with the Earthco synthetic-fuel audit. While we feel good about our case, we can't predict the outcome.

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Progress Energy Annual Report 2004 EXECUTIVE AND SENIOR OFFICERS Robert B.McGehee Donald K.Davis Chairman and Chief Executive Officer Executive Vice President- Diversified Operations William D.Johnson C.S.Hinnant President and Chief Operating Officer Senior Vice President - Nuclear Generation Peter M.Scott IlIl Jeffrey J. Lyash President and Chief Executive Officer Senior Vice President - Energy Delivery Progress Energy Service Company, LLC Progress Energy Florida, Inc.

Fred N.Day IV John R.McArthur President and Chief Executive Officer Senior Vice President- Corporate Relations, Progress Energy Carolinas, Inc. General Counsel and Secretary H.William Habermeyer, Jr. E.Michael Williams President and Chief Executive Officer Senior Vice President- Power Operations Progress Energy Florida, Inc.

Lloyd M.Yates Geoffrey S. Chatas Senior Vice President - Energy Delivery Executive Vice President and Progress Energy Carolinas, Inc.

Chief Financial Officer FINANCIAL REPORT Management's Discussion and Analysis ............................... 20 Market Risk Disclosures ............................... 48 Forward-Looking Statements ............................................................................ 51 Independent Auditors' and Management Reports ............................... 52 Consolidated Financial Statements Income ............................... 55 Balance Sheets ............................... 56 Cash Flows ............................... 58 Changes in Common Stock Equity ............................... 59 Comprehensive Income ............................... 59 Notes to Consolidated Financial Statements ............................... 60 Selected Consolidated Financial and Operating Data (Unaudited) ........................................... 110 Reconciliation of Ongoing Earnings Per Share to Reported GAAP Earnings Per Share (Unaudited) ...... ....... 111 19

V Management's Discussion and Analysis The following Management's Discussion and Analysis Strategy contains forward-looking statements that involve estimates, projections, goals, forecasts, assumptions, Progress Energy isan integrated energy company, with risks and uncertainties that could cause actual results or its primary focus on the end-use and wholesale outcomes to differ materially from those expressed in the electricity markets. The Company operates in retail utility forward-looking statements. Please review the 'Safe markets inthe southeastern United States and competitive Harbor For Forward-Looking Statements for a discussion markets in the eastern United States. The target is to of the factors that may impact any such forward-looking develop a business mix of approximately 80% regulated statements made herein. Management's Discussion and and 20% nonregulated business. The Company isfocused Analysis should be read in conjunction with the Progress on achieving the following key goals: restoring balance Energy Consolidated Financial Statements. sheet strength and flexibility, disciplined capital and operations and maintenance (O&M) management to INTRODUCTION support earnings and current dividend policy and achieving constructive regulatory frameworks in all three The Company's reportable business segments and their regulated jurisdictions. A summary of the significant primary operations include: financial objectives or issues impacting Progress Energy,

• Progress Energy Carolinas Electric (PEC Electric) - its regulated utilities and nonregulated operations is primarily engaged in the generation, transmission, addressed more fully inthe following discussion.

distribution and sale of electricity in portions of North Carolina and South Carolina; Progress Energy has several key financial objectives, the

• Progress Energy Florida (PEF) - primarily engaged in first of which isto achieve sustainable earnings growth in the generation, transmission, distribution and sale of its three core energy businesses, which include PEC electricity in portions of Florida; Electric, PEF and Progress Ventures (excluding synthetic fuels). Inaddition, the Company seeks to continue its track

• Competitive Commercial Operations (CCO) - engaged in nonregulated electric generation operations and record of dividend growth, as the Company has increased its dividend for 17 consecutive years, and 29 of the last 30.

marketing activities primarily in the southeastern The Company also seeks to restore balance sheet strength United States; and flexibility by reducing its debt to total capitalization

• Fuels - primarily engaged in natural gas production in ratio through selected asset sales, free cash flow (defined Texas and Louisiana, coal mining and related services, as cash from operations less capital expenditures and and the production of synthetic fuels and related common dividends) and increased equity from retained services, which are located in Kentucky, West Virginia earnings and ongoing equity issuances.

and Virginia; and

• Rail Services (Rail) - engaged in various rail and railcar- In the short term the Company's ability to achieve its related services in 23 states, Mexico and Canada. objectiveswill be impacted by, among otherthings,its ability to recover storm costs incurred during 2004, cash flow The Progress Ventures business unit consists of the available to reduce debt after funding capital expenditures Fuels and CCO operating segments. The Corporate and and common dividends, obtaining a reasonable rate Other category includes other businesses engaged agreement in Florida at the expiration of the current in other nonregulated business areas, including agreement in December 2005 and the outcome of the telecommunications, primarily in the eastern United ongoing Internal Revenue Service (IRS) audit of the States, and energy services operations and holding Company's synthetic fuel facilities. The Company's long-company results, which do not meet the requirements term challenges include escalating nonfuel operating costs, for separate segment reporting disclosure. the need for sufficient earnings growth to sustain the track record of dividend growth, and the scheduled expiration of In 2004, the Company realigned its business segments to the Section 29 tax credit program for its synthetic fuels no longer report the other nonregulated businesses as a business at the end of 2007.

reportable business segment. For comparative purposes, 2003 and 2002 segment information has been restated to The Company's ability to meet its financial objectives is align with the 2004 reporting structure. largely dependent on the earnings and cash flows of its two regulated utilities. The regulated utilities contributed

$797 million of net income and produced 100% of consolidated cash flow from operations in 2004. In 20

Progress Energy Annual Report 2004 addition, Fuels contributed $180 million of net income, of Section under FUTURE LIQUIDITY AND CAPITAL which $91 million represented synthetic fuel net income. RESOURCES below for more information regarding the Partially offsetting the net income contribution provided potential impact on the Company's financial condition by the regulated utilities and Fuels was a loss of and results of operations resulting from a ratings

$236 million recorded at Corporate and Other, primarily downgrade.

related to interest expense on holding company debt REGULATED UTILITIES While the Company's synthetic fuel operations currently The regulated utilities earnings and operating cash flows provide significant earnings that are scheduled to expire are heavily influenced by weather, including related atthe end of 2007, the associated cash flow benefits from storm damage, the economy, demand for electricity synthetic fuels are expected to come in the future when related to customer growth, actions of regulatory deferred tax credits are ultimately utilized. Credits that agencies and cost controls.

have been generated but not yet utilized are carried forward indefinitely as alternative minimum tax credits Both PEC Electric and PEF operate in retail service and will provide positive cash flow when utilized. At territories that are forecasted to have income and December 31, 2004, deferred credits were $745 million. population growth higher than the U.S. average. In recent See Note 23E for additional information on the Company's years, lower industrial sales mainly related to weakness in synthetic fuel operations and its ability to utilize its the textile sector at PEC Electric have negatively impacted current and future tax credits. earnings growth. The Company does not expect any significant improvement in industrial sales in the near Progress Energy reduced its debt to total capitalization term. These combined factors under normal weather ratio to 57.6% at the end of 2004 as compared to 58.8% at conditions are expected to contribute approximately the end of 2003. The Company seeks to continue to 2%annual retail kilowatt-hour (KWh) sales growth at PEC improve this ratio as it plans to reduce total debt with Electric and approximately 3%annual retail kilowatt-hour proceeds from asset sales, free cash flow (defined as cash (KWh) sales growth at PEF through at least 2007. The from operations less capital expenditures and common utilities must continue to invest significant capital in new dividends) and growth in equity from retained earnings generation, transmission and distribution facilities to and ongoing equity issuances. The Company expects total support this load growth. Subject to regulatory approval, capital expenditures to be approximately $1.3 billion in these investments are expected to increase the utilities' both 2005 and 2006. rate base, upon which additional return can be realized that creates the basis for long-term financial growth in the Progress Energy's ratings outlook was changed to utilities. The Company will meet this load growth through negative" from 'stable" in 2004 by both Moody's and the two previously planned approximately 500 MW Standard & Poor's (S&P). Both these ratings agencies combined-cycle units at PEFs Hines Energy Complex in cited the uncertainty around the timing of storm 2005 and 2007. The contribution from the utilities' regulated cost recovery, potential delays in the Company's wholesale business is expected to increase slightly in 2005 de-leveraging plan, uncertainty about the upcoming rate and be relatively flat over the following few years.

case in Florida and uncertainty about the IRS audit of the Company's synthetic fuel partnerships in their ratings While the two utilities expect retail sales growth in the actions. The change in outlook has not materially affected future, they are facing rising costs. The Company began Progress Energy's access to liquidity or the cost of its a cost-management initiative in late 2004 to permanently short-term borrowings. If Standard & Poor's lowers reduce by$75 million to $100 million the projected growth Progress Energy's senior unsecured rating one ratings in the Company's annual nonfuel O&M costs by the end of category to BB+ from its current rating, it would be a non- 2007. See 'Cost-Management Initiative' under RESULTS investment grade rating. The effect of a noninvestment OF OPERATIONS for more information. The utilities grade rating would primarily be to increase borrowing expect capital expenditures to be approximately $1.1 costs. The Company's liquidity would essentially remain billion in both 2005 and 2006. The Company will continue unchanged as the Company believes it could borrow an approximate $900 million program of installing new under its revolving credit facilities instead of issuing emission-control equipment at PEC's coal-fired power commercial paper for its short-term borrowing needs. plants in North Carolina. Operating cash flows are However, there would be additional funding requirements expected to be sufficient to fund capital spending in 2005 of approximately $450 million due to ratings triggers and in 2006.

embedded in various contracts. See 'Guarantees' 21

V Management's Discussion and Analysis The costs associated with the unprecedented series of increase CCO's revenue and cost of sales from 2004 to major hurricanes that impacted the Company's service 2005 with lower margins expected. Currently CCO has territories significantly impacted the utility operations in contracts for its planned production capacity, which 2004. Restoration of the Company's systems from includes callable resources from the cooperatives, of hurricane-related damage cost almost $400 million. approximately 77% for 2005, 81% for 2006 and 75% for Although PEF has filed for recovery of approximately 2007. CCO will continue its optimization strategy for the

$252 million of these storm costs, the timing of recovery is nonregulated generation portfolio.

not certain at this time. See OTHER MATTERS below for more information on storm costs incurred during 2004. Fuels will continue to develop its natural gas production asset base both as a long-term economic hedge for the PEC Electric and PEF continue to monitor progress Company's nonregulated generation fuel needs and toward a more competitive environment. No retail to continue its presence in natural gas markets that electric restructuring legislation has been introduced in will allow it to provide attractive returns for the the jurisdictions in which PEC Electric and PEF operate. Company's shareholders.

As part of the Clean Smokestacks bill in North Carolina and an agreement with the Public Service Commission The Company has begun exploring strategic alternatives of South Carolina (SCPSC), PEC Electric is operating regarding the Fuels' coal mining business, which could under a rate freeze in North Carolina through 2007 and include divesting assets. As of December 31, 2004, the an agreement not to seek a base retail electric rate carrying value of long-lived assets of the coal mining increase in South Carolina through 2005. PEF is business was $66 million.

operating under a retail rate agreement in Florida through 2005. PEF has initiated a rate proceeding in 2005 The Company, through its subsidiaries, is a majority regarding its future base rates. See Note 8 for further owner in five entities and a minority owner in one entity discussion of the utilities' retail rates. that owns facilities that produce synthetic fuel as defined under the Internal Revenue Code. The production and NONREGULATED BUSINESSES sale of the synthetic fuel from these facilities qualifies for The Company's primary nonregulated businesses are tax credits under Section 29 if certain requirements are CCO, Fuels and Progress Rail. satisfied. These facilities have private letter rulings (PLRs) from the IRS with respect to their synthetic fuel operations. However, these PLRs do not address placed-Cash flows and earnings of the nonregulated businesses are impacted largely by the ability to obtain additional in-service date requirements. The Company has resolved certain synthetic fuel tax credit issues with the IRS and is term contracts or sell energy on the spot market at favorable terms, the volume of synthetic fuel produced continuing to work with the IRS to resolve any remaining and tax credits utilized, and volumes and prices of both issues. The Company cannot predict the final resolution of any outstanding matters. The Company has no current coal and natural gas sales.

plans to alter its synthetic fuel production schedule as a Progress Energy expects an excess of supply in the result of these matters. The Company plans to produce wholesale electric energy market for the next several approximately 8million to 12 million tons of synthetic fuel years. During 2004, CCO entered into additional in 2005. Through December 31, 2004, the Company had wholesale power contracts with cooperatives in Georgia generated approximately $1.5 billion of synthetic fuel tax and will serve approximately one-third of the Georgia credits to date (including FPC prior to the acquisition by cooperative market starting in 2005. CCO completed the the Company). See additional discussion of synthetic fuel build out of its nonregulated generation assets in 2003 tax credits in Note 23E.

and currently has total capacity of 3,100 MW. The In February 2005, Progress Energy signed a definitive Company has no current plans to expand its portfolio of nonregulated generating plants. CCO short-term agreement to sell its Progress Rail subsidiary to subsidiaries of One Equity Partners LLC for a sales price challenges include absorbing the fixed costs associated with these plants and the general weakness inwholesale of S405 million. Proceeds from the sale are expected to be power markets. Three above-market tolling agreements used to reduce debt. See Note 24 for more information.

for approximately 1,200 MW of capacity expired at the end of 2004. CCO has replaced the expired agreements Progress Energy and its consolidated subsidiaries are with the increased cooperative load in Georgia. The subject to various risks. For a complete discussion of increased cooperative load in Georgia will significantly these risks, see the Company's filings with the SEC.

22

Progress Energy Annual Report 2004 RESULTS OF OPERATIONS

• Reduction in losses recorded for discontinued operations.

For 2004 as compared to 2003 and 2003 as compared to 2002

• Reduction in losses recorded for changes in accounting principles.

In this section, earnings and the factors affecting earnings are discussed. The discussion begins with a For the year ended December 31, 2003, Progress Energy's summarized overview of the Company's consolidated net income was $782 million, or$3.30 per share, compared earnings, which is followed by a more detailed to $528 million, or $2.43 per share, for the same period in discussion and analysis by business segment 2002. Income from continuing operations before the cumulative effect of changes in accounting principles and Overview discontinued operations was $811 million in 2003, a 47%

increase from $552 million in 2002. Net income for 2003 For the year ended December 31,2004, Progress Energy's increased compared to 2002 primarily due to the inclusion net income was S759 million or$3.13 per share compared in 2002 of an impairment of $265 million after-tax related to to $782 million or $3.30 per share for the same period in assets in the telecommunications and rail businesses.

2003. The decrease in net income as compared to prior The Company recorded impairments of $23 million after-year was due primarily to: tax in 2003 on an investment portfolio and on long-lived

• Reduction in synthetic fuel earnings due to lower assets. The increase in net income in 2003 of $12 million, synthetic fuel sales due to the impact of hurricanes excluding the impairments, is primarily due to:

during the year.

• Increase in retail customer growth at the utilities.

• Lower off-system wholesale sales, primarily at

• Growth in natural gas production and sales.

PEC Electric.

• Higher synthetic fuel sales.

• Higher O&M expenses at PEC Electric.

• Absence of severe storm costs incurred in 2002 in

• Recording of litigation settlement reached in the civil the Carolinas.

suit by Strategic Resource Solutions (SRS).

• Lower loss recorded in 2003 related to the sale of North

• Decreased nonregulated generation earnings due to Carolina Natural Gas Company (NCNG), with the receipt of a contract termination payment on a tolling majority of the loss on the sale being recorded in 2002.

agreement in 2003, loss recognized on early extinguishment of debt in 2004 and higher fixed costs

• Lower interest charges in 2003.

and interest charges in 2004.

• Reduction in revenues due to customer outages in Partially offsetting these items were the:

Florida associated with the hurricanes.

• Net impact of the 2002 Florida Rate settlement.

• Increased interest charges due to the reversal of

• Impact of the change in the fair value of the CVOs.

interest expense for resolved tax matters in 2003.

• Milder weather in 2003 as compared to 2002.

• Increased benefit-related costs.

Partially offsetting these items were:

• Higher depreciation expense at both utilities and the

• Favorable weather in the Carolinas. Fuels and CCO segments.

• Reduction in revenue sharing provisions in Florida.

• The impact of changes in accounting principles in 2003.

• Favorable customer growth in both the Carolinas and Florida. Basic earnings per share decreased in 2004 and increased

• Increased margins as a result of the allowed return on in 2003 due in part to the factors outlined above. Dilution the Hines Unit 2 in Florida. related to issuances under the Company's Investor Plus

• Increased earnings for natural gas operations, which and employee benefit programs in 2004 also reduced basic include the gain recorded on the disposition of certain earnings per share by $0.06 in 2004. Dilution related to a Winchester Production Company assets. November 2002 equity issuance of 14. million shares and issuances under the Company's Investor Plus and

• Increased earnings for Rail operations. employee benefit programs in 2002 and 2003 also reduced

• Unrealized gains recorded on contingent value basic earnings per share by $0.33 in 2003.

obligations (CVOs).

• Reduction in impairments recorded for an investment Beginning in the fourth quarter of 2003, the Company portfolio and long-lived assets. ceased recording portions of the Fuels segment's 23

V Management's Discussion and Analysis operations, primarily synthetic fuel facilities, one month in 2005. The cost-management initiative is designed to arrears. As a result, earnings forthe yearended December permanently reduce by $75 million to $100 million the 31, 2003, included 13 months of operations, resulting in a projected growth in the Company's annual operation and net income increase of $2million for the year. maintenance expenses bythe end of 2007. Inadditiontothe workforce restructuring, the cost-management initiative The Company's segments contributed the following profit includes avoluntary enhanced retirement program.

or loss from continuing operations:

In connection with the cost-management initiative, the (inmillions) 2004 Change 2003 Change 2002 Company expects to incur one-time pre-tax charges of PEC Electric $464 $151) $515 $2 $513 approximately $130 million. Approximately $30 million of PEF 333 38 295 128) 323 that amount relates to payments for severance benefits, Fuels 180 (55) 235 59 176 and will be recognized in the first quarter of 2005 and paid CCO (4) (24) 20 17) 27 over time. The remaining approximately $100 million will Rail services 16 17 11) 41 (42) be recognized in the second quarter of 2005 and relates Total segment primarily to postretirement benefits that will be paid over profit (loss) 989 (75) 1,064 67 997 time to those eligible employees who elect to participate Corporate and other 1236) 17 (253) 192 (445) in the voluntary enhanced retirement program.

Total income from Approximately 3,500 of the Company's 15,700 employees continuing operations 753 (58) 811 259 552 are eligible to participate in the voluntary enhanced Discontinued operations, retirement program. The total cost-management initiative netof tax 6 14 (8) 16 124)

Cumulative effect of charges could change significantly depending upon how changes in many eligible employees elect early retirement under the accounting principles - 21 (21) (21) - voluntary enhanced retirement program and the salary, Netincome S759 $123) S782 $254 $528 service years and age of such employees (See Note 24).

Energy Delivery Capitalization Practice In March 2003, the SEC completed an audit of Progress The Company has reviewed its capitalization policies for Energy Service Company, LLC (Service Company), and its Energy Delivery business units in PEC and PEF. That recommended that the Company change its cost allocation review indicated that in the areas of outage and methodology for allocating Service Company costs. As emergency work not associated with major storms and part of the audit process, the Company was required to allocation of indirect costs, both PEC and PEF should change the cost allocation methodology for 2003 and revise the way that they estimate the amount of capital record retroactive reallocations between its affiliates inthe costs associated with such work. The Company has first quarter of 2003 for allocations originally made in 2001 implemented such changes effective January 1, 2005, and 2002. This change in allocation methodology and the which include more detailed classification of outage and related retroactive adjustments have no impact on emergency work and result in more precise estimation consolidated expense or earnings. The new allocation and a process of retesting accounting estimates on an methodology, as compared to the previous allocation annual basis. As a result of the changes in accounting methodology, generally decreases expenses in the estimates for the outage and emergency work and regulated utilities and increases expenses in the indirect costs, a lesser proportion of PEC's and PEF's nonregulated businesses. The regulated utilities' costs will be capitalized on a prospective basis. The reallocations are within O&M expense, while the Company estimates that the combined impact for both diversified businesses' reallocations are generally within utilities in 2005 will be that approximately $55 million of diversified business expenses. The impact on the individual costs that would have been capitalized under the lines of business is included in the following discussions. previous policies will be expensed. Pursuant to SFAS No.

71, PEC and PEF have informed the state regulators Cost-Management Initiative having jurisdiction over them of this change and that the On February 28, 2005, as part of a previously announced new estimation process will be implemented effective cost-management initiative, the executive officers of the January 1, 2005. The Company has also requested a Company approved a workforce restructuring. The method change from the IRS.

restructuring will result in a reduction of approximately 450 positions and is expected to be completed in September of 24

Progress Energy Annual Report 2004 Progress Energy Carolinas Electric revenues was due primarily to increased retail revenues of $35 million as a result of favorable weather, with cooling PEC Electric contributed segment profits of $464 million, degree days 16% above prior year. Retail customer

$515 million and $513 million in 2004, 2003 and 2002, growth contributed an additional $55 million in revenues in respectively. The decrease in profits for 2004 as compared 2004. PEC Electric's retail customer base increased as to 2003 is primarily due to higher O&M charges and lower approximately 26,000 new customers were added in 2004.

wholesale revenues partially offset by the favorable The increase in retail revenues was offset partially impact of weather, increased revenues from customer by lower wholesale revenues. Wholesale revenues growth and a reduction in investment losses and decreased $86 million when compared to $393 million in impairment charges compared to the prior year. The slight 2003. The decrease in PEC Electric's wholesale revenues increase in profits in 2003, when compared to 2002, was in 2004 from 2003 is primarily the result of reduced excess primarily due to customer growth, strong wholesale sales generation sales. Revenues for 2003 included strong sales during the first quarter of 2003, lower Service Company to the northeastern United States as a result of favorable allocations and lower interest costs, which were offset by market conditions. Inaddition, lower contracted capacity unfavorable weather in 2003, higher depreciation expense compared to 2003 further reduced wholesale revenues.

and increased benefit-related costs. The remaining reduction in wholesale revenues is attributable to an inelastic power market While the cost REVENUES of fuel continues to rise, the power market prices have not PEC Electric's electric revenues and the percentage responded as quickly to the fuel increases. The change by year and by customer class are as follows: differential between fuel cost and market price limited opportunities to enter the market. PEC monitors its (inmillions] wholesale contract portfolio on a regular basis. During Customer Class 2004 % Change 2003 %Change 2002 2003 and 2004, several contracts expired or were Residential $1,324 5.2 S1,259 1.5 S1,241 renegotiated at lower prices. Due to the slightly Commercial 888 4.5 850 2.2 832 depressed wholesale market and increased competition, Industrial 659 3.6 636 (1.4) 645 this trend could continue as contracts are renewed in the Governmental 82 3.8 79 1.3 78 upcoming years. The expiration and renegotiation of Total retail wholesale contracts is a normal business activity. PEC revenues 2.953 4.6 2,824 1.0 2,796 actively manages its portfolio by seeking to sign new Wholesale 575 (16.3) 687 5.5 651 contracts to replace expiring arrangements.

Unbilled 10 - (6) - 15 Miscellaneous 90 7.1 84 9.1 77 PEC Electric's revenues, excluding recoverable fuel Total electric revenues of $901 million and S851 million in 2003 and 2002, revenues $3,628 1.1 $3,589 1.4 $3,539 respectively, were unchanged from 2002 to 2003. Milder weather in 2003, when compared to 2002, accounted for a $61 million retail revenue reduction. While heating PEC Electric's electric energy sales and the percentage change by year and by customer class are as follows: degree days in 2003 were 4.8% above prior year, cooling degree days were 25.2% below prior year. However, the (inthousands of MM) more severe weather in the northeast region of the

.

Customer Class 2004 %Change 2003 %Change 2002 United States during the first quarter of 2003 drove a Residential 16.003 4.7 15,283 0.3 15,239 $19 million increase in wholesale revenues. Additionally, Commercial 13,019 3.7 12,557 0.7 12,468 retail customer growth in 2003 generated an additional Industrial 13,036 2.3 12,749 (2.6) 13,089 S42 million of revenues in 2003. PEC Electric's retail Governmental 1.431 1.6 1,408 (2.0) 1,437 customer base increased as approximately 23,000 new Total retail customers were added in 2003.

energy sales 43,489 3.6 41,997 (0.6) 42,233 Wholesale 13722 (14.8) 15,518 3.3 15,024 Downturns in the economy during 2002 and 2003 impacted Unbilled 91 - (44) - 270 energy usage within the industrial customer class. Total Total MWh sales 56,802 1.2 57,471 (0.1) 57,527 industrial revenues, excluding fuel revenues, declined during 2003 when compared to 2002 by $13 million, as PEC Electric's revenues, excluding recoverable fuel sales to industrial customers decreased due to a general revenues of $933 million and $901 million for 2004 and industrial slowdown. Decreases in the textile industry and the chemical industry were among the largest. This 2003, respectively, increased $7 million. The increase in 25

V Managements Discussion and Analysis declining trend leveled out in 2004 as industrial sales Operations and Maintenance (O&M) increased in the primary and fabricated metal, chemicals, O&M expenses were $871 million for 2004, which lumber and food industries. Industrial sales growth is represents an $89 million increase compared to 2003.

expected to be flat or very low as expired textile quotas This increase is driven primarily by higher outage costs are expected to lower textile sales and balance gains in and storm costs in 2004 than in the prior year. Outages other industries.

increased O&M costs by $29 million primarily due to an increase in the number and scope of nuclear plant EXPENSES outages in 2004. In addition, costs associated with Fuel and Purchased Power restoration efforts after severe storms increased O&M Fuel and purchased power costs represent the costs of expense $18 million. Storm costs for 2004 included costs generation, which include fuel purchases for generation, related to an ice storm and Hurricanes Charley and Ivan as well as energy purchased in the market to meet in the North Carolina service territory. PEC Electric also customer load. Fuel and purchased power expenses are incurred storm costs in 2003; however, the Company recovered primarily through cost recovery clauses, and, requested and the NCUC approved deferral of these as such, changes in these expenses do not have a costs. The Company did not seek to defer costs material impact on earnings. The difference between fuel associated with the ice storm, which hit the North and purchased power costs incurred and associated fuel Carolina service territory, and Hurricanes Charley and revenues that are subject to recovery is deferred for Ivan. O&M expenses also increased $9 million due to future collection or refund to customers. higher salary- and benefit-related expenditures. In addition, O&M charges in the prior year were favorably Fuel and purchased power expenses were $1.137 billion for impacted by $16 million related to the retroactive 2004, which represents a$16 million increase compared to reallocation of Service Company costs.

the same period in the prior year. Fuel used in electric generation increased SII million to $836 million compared O&M expenses were $782 million in 2003, which to the prior year. This increase isdue to an increase in fuel represents a $20 million decrease compared to 2002.

used in generation of $78 million due to higher fuel costs O&M expense in 2002 included severe storm costs of and a change in generation mix. Higher fuel costs are being $27 million. Those costs, along with lower 2003 Service driven primarily by an increase in coal prices. Outages at Company allocations of $16 million, due to the change in several nuclear facilities during the year resulted in allocation methodology as required by the SEC in early increased combustion turbine generation, which has a 2003, are the primary reasons for decreased O&M higher average fuel cost The increase in fuel used in expenses. This decrease was partially offset by higher generation isoffset by areduction in deferred fuel expense benefit-related costs of $21 million. PEC Electric incurred as a result of the underrecovery of current period fuel O&M costs of S25 million related to three severe storms in costs. Purchased power expenses increased $5million to 2003. The NCUC allowed deferral of $24 million of these

$301 million compared to prior year. The increase in storm costs. These costs are being amortized over a five-purchased power is due primarily to an increase in price. year period, beginning in the months the expenses were incurred. PEC Electric amortized $3million of these costs Fuel and purchased power expenses were $1.121 billion for in 2003, which isincluded in depreciation and amortization 2003, which represents a $22 million increase compared to expense on the Consolidated Income Statement the same period in the prior year. Fuel used in electric generation increased $73 million in 2003, compared to prior Depreciation and Amortization year, primarily due to higher prices incurred for coal, oil and Depreciation and amortization expense was $570 million natural gas used during generation. Costs for fuel per Btu for 2004, which represents an $8 million increase increased for all three commodities during the year. compared to 2003. This increase is attributable primarily Purchased power expense decreased $51 million in 2003, to the impact of the NC Clean Air legislation. PEC Electric compared to $347 million in 2002, mainly due to a decrease recorded the maximum amortization allowed under the inthe volume purchased as milder weather reduced system legislation in 2004. NC Clean Air amortization increased requirements and due to the renegotiation at more favorable $100 million to $174 million in 2004 compared to $74 million terms of two contracts that expired during the year. in 2003. Depreciation expense also increased $9million for assets placed in service. These increases were partially offset by a reduction in depreciation expense related to depreciation studies filed during the year.

26

Progress Energy Annual Report 2004 During 2004, PEC met the requirements of both the NCUC Progress Energy Florida and the SCPSC for the implementation of depreciation studies that allowed the utility to reduce the rates used to PEF contributed segment profits of $333 million, calculate depreciation expense. The annual reduction in $295 million and $323 million in 2004, 2003 and 2002, depreciation expense is approximately $82 million respectively. Profits for 2004 increased due to favorable compared to 2003. The reduction is due primarily to customer growth, a reduction inthe provision for revenue extended lives at each of PEC's nuclear units. The new sharing, favorable wholesale revenues, the additional rates became effective January 2004. return on investment on the Hines Unit 2 and reduced O&M expenses. These items were partially offset by Depreciation and amortization increased $38 million in unfavorable weather, a reduction in revenues related to 2003, compared to $524 million in 2002. Depreciation and the hurricanes, increased interest expense and increased amortization increased $74 million related to the 2003 impact depreciation expense from assets placed in service. The of the NC Clean Air legislation and decreased $53 million decrease in profits in 2003, when compared to 2002, was related to the 2002 impact of the accelerated nuclear primarily due to the impact of the 2002 rate case amortization program. Both programs are approved bythe stipulation, higher benefit-related costs primarily related to state regulatory agencies and are discussed further at higher pension expense, higher depreciation and the Notes 8B and 22. In addition, depreciation increased unfavorable impact of weather. These amounts were

$19 million due to additional assets placed into service. partially offset by continued customer growth and lower interest charges.

Taxes Other than on Income In 2002, PEF's profits were affected by the outcome of the Taxes other than on income were $173 million for 2004, rate case stipulation, which included a one-time retroactive which represents an $11 million increase compared to revenue refund, a decrease in retail rates of 9.25% (effective the prior year. This increase is due primarily to an May 1,2002), provisions for revenue sharing with the retail increase in gross receipts taxes of $8million related to an customer base, lower depreciation and amortization and increase in revenues and a 2004 adjustment related to the increased service revenue rates (See Note 8C).

prior year. The remaining variance in other taxes is due to an increase in property taxes of $7million due to higher REVENUES property appraisals partially offset by a reduction in payroll taxes of $4million. PEF's electric revenues and the percentage change by year and by customer class, as well as the impact of the Taxes other than on income were $162 million in 2003, rate case settlement on revenue, are as follows:

which represents a$4million increase compared to prior (inmillionsJ year. This increase is due to an increase in property taxes Customer Class 2004 %Change 2003 %Change 2002 and payroll taxes of $2million each. Residential S1.806 6.8 $1,691 2.8 $1,645 Commercial 853 15.3 740 1.2 731 Interest Expense Industrial 254 16.0 219 3.8 211 Net interest expense was $192 million, $197 million and Governmental 211 16.6 181 4.6 173 S212 million in 2004, 2003 and 2002, respectively. Declines Revenue sharing in interest expense in 2003 resulted from reduced short- refund (11) - (35) - (5) term debt and refinancing certain long-term debt with Retroactive retail rate refund - - - - (35) lower interest rate debt.

Total retail revenues 3.113 11.3 2,796 2.8 2,720 Income Tax Expense Wholesale 268 18.1 227 (1.3) 230 Income tax expense was $237 million, $238 million and Unbilled 7 - (2) - (3)

$237 million in 2004, 2003 and 2002, respectively. In 2004, Miscellaneous 137 4.6 131 13.9 115 2003 and 2002, S22 million, $24 million and $35 million, Total electric respectively, of the tax benefitthatwas previously held at revenues $3.525 11.8 $3,152 2.9 S3,062 the Company's holding company was allocated to PEC Electric. As required by an SEC order issued in 2002, certain holding company tax benefits are allocated to profitable subsidiaries. Other fluctuations in income taxes are primarily due to changes in pre-tax income.

27

V Management's Discussion and Analysis PEF's electric energy sales and the percentage change $12 million in 2003 compared to the $5 million provision by year and by customer class are as follows: recorded in 2002. Revenues in 2003 were also impacted by the final resolution of the 2002 revenue sharing provisions, (inthousands of MIM])

as the FPSC issued an order in July 2003 that required PEF Customer Class 2004 % Change 2003 % Change 2002 to refund an additional $18 million to customers related to Residential 19,347 (0.4) 19,429 3.6 18,754 2002. The 9.25% rate reduction from the settlement Commercial 11,734 1.6 11,553 1.2 11,420 accounted for an additional $46 million decline in revenues.

Industrial 4,069 1.7 4,000 4.3 3,835 The 2003 impact of the rate settlement was partially offset Governmental 3,044 2.4 2,974 4.4 2,850 by the absence of the prior year interim rate refund of Total retail $35 million. Lower wholesale revenues (excluding fuel energy sales 38,194 0.6 37,956 3.0 36,859 revenues) of $17 million and the $8million impact of milder Wholesale 5,101 18.0 4,323 3.4 4,180 weather also reduced base revenues during 2003.

Unbilled 358 - 233 - 5 Total MWh sales 43,653 2.6 42,512 3.6 41,044 EXPENSES Fuel and Purchased Power PEFs revenues, excluding recoverable fuel and other pass-through revenues of $2.007 billion and $1.692 billion Fuel and purchased power costs represent the costs of for 2004 and 2003, respectively, increased $58 million. This generation, which include fuel purchases for generation, increase was due primarily to favorable customer growth, as well as energy purchased in the market to meet which increased revenues $34 million. PEF has 37,000 customer load. Fuel and purchased power expenses are additional retail customers compared to prior year. recovered primarily through cost recovery clauses, and, Revenues were also favorably impacted by a reduction in as such, changes in these expenses do not have a the provision for revenue sharing of $24 million. Results for material impact on earnings. The difference between fuel 2003 included an additional refund of $18 million related to and purchased power costs incurred and associated fuel the 2002 revenue sharing provision as ordered by the revenues that are subject to recovery is deferred for Florida Public Service Commission (FPSC) in July 2003. In future collection or refund to customers.

addition, improved wholesale sales increased revenues by$11 million. Included in fuel revenues is the recovery of Fuel and purchased power expenses were $1.742 billion in depreciation and capital costs associated with the Hines 2004, which represents a $306 million increase compared Unit 2,which was placed into service in December 2003 to 2003. This increase is due to increases in fuel used in and contributed $36 million in additional revenues in 2004. electric generation and purchased power expenses of The recovery of the Hines Unit 2 costs through the fuel $305 million and $1 million, respectively. Higher system clause is in accordance with the 2002 rate stipulation (See requirements and increased fuel costs in the currentyear Note 8C). These increases were partially offset by the account for $87 million of the increase in fuel used in reduction in revenues related to customer outages for electric generation. The remaining increase is due to the Hurricanes Charley, Frances and Jeanne of approximately recovery of fuel expenses that were deferred in the prior

$12 million and the impact of milderweather in the current year, partially offset by the deferral of current year year of $10 million. underrecovered fuel expenses. In November 2003, the FPSC approved PEF's request for a cost adjustment in its PEF's revenues, excluding recoverable fuel and other annual fuel filing due to the rising costs of fuel. The new pass-through revenues of S1.692 billion and $1.602 billion in rates became effective January 2004.

2003 and 2002, respectively, were unchanged from 2002 to 2003. Revenues were favorably impacted by $49 million Fuel used in generation and purchased power expenses in 2003, primarily as a result of customer growth were $1.436 billion in 2003, which represents an (approximately 36,000 additional customers). In addition, $87 million increase compared to the prior year. Higher other operating revenues were favorable by$16 million due costs to generate electricity and higher purchased primarily to higher wheeling and transmission revenues power costs as a result of an increase in volume due to and higher service charge revenues (resulting from system requirements and higher natural gas prices increased rates allowed under the 2002 rate settlement). resulted in a $229 million increase partially offset by the These increases were offset by the negative impact of the deferral of 2003 underrecovered fuel and purchased rate settlement, which decreased revenues, lower power expense of $142 million.

wholesale sales and the impact of unfavorable weather.

The provision for revenue sharing increased 28

Progress Energy Annual Report 2004 Operations and Maintenance (O&M) receipts and franchise taxes of $8million and $7 million, respectively, related to an increase in revenues and an O&M expenses were $630 million in 2004, which increase in property taxes of $5million due to increases represents a $10 million decrease when compared to the in property placed in service and tax rates. These prior year. This decrease is primarily related to favorable increases were partially offset by a reduction in payroll benefit-related costs of $16 million, primarily due to lower taxes of $7million.

pension costs, which resulted from improved pension asset performance.

Taxes other than on income were $241 million in 2003, which represents an increase of $13 million compared to O&M expenses were $640 million in 2003, which prior year. This increase was due to increases in payroll represents a $49 million increase when compared to the taxes of $10 million and increases in gross receipts and prior year. The increase is largely related to increases in franchise taxes of $4million combined.

certain benefit-related expenses of $36 million, which consisted primarily of higher pension expense of Interest Expense

$27 million and higher operational costs related to the Crystal River Unit 3 nuclear outage and plant maintenance. Interest charges, net were $114 million in 2004, which represents an increase of $23 million compared to the Depreciation and Amortization prior year. Interest charges, net were $91 million in 2003, which represents a $15 million decrease compared to Depreciation and amortization expense was $281 million the prior year. The fluctuations were primarily due to for 2004, which represents a decrease of $26 million interest costs in 2003 being favorably impacted by the when compared to the prior year, primarily due to the reversal of interest expense due to the resolution of amortization of the Tiger Bay regulatory asset in the prior certain tax matters.

year. The Tiger Bay regulatory asset, for contract termination costs, was recovered pursuant to an Income Tax Expense agreement between PEF and the FPSC that was approved in 1997. The amortization of the regulatory Income tax expense was $174 million, $147 million and asset was calculated using revenues collected underthe $163 million in 2004, 2003 and 2002, respectively. In 2004, fuel adjustment clause; as such, fluctuations in this 2003 and 2002, $14 million, $13 million and $20 million, expense did not have an impact on earnings. During 2003, respectively, of the tax benefitthatwas previously held at Tiger Bay amortization was $47 million. The Tiger Bay the Company's holding company was allocated to PEF. As asset was fully amortized in September 2003. The required by an SEC order issued in 2002, certain holding decrease in Tiger Bay amortization was partially offset by company tax benefits are allocated to profitable additional depreciation for assets placed in service, subsidiaries. Other fluctuations in income taxes are including depreciation for Hines Unit 2, of approximately primarily due to changes in pre-tax income.

$9 million. This depreciation expense is being recovered through the fuel cost recovery clause as allowed by the Diversified Businesses FPSC. See discussion of the return on Hines 2 in the The Company's diversified businesses consist of revenues analysis above. the Fuels segment, the CCO segment and the Rail Services segment.

Depreciation and amortization was S307 million in 2003, which represents an increase of $12 million when Fuels compared to 2002. Depreciation increased primarily as a result of additional assets being placed into service that The Fuels' segment operations include synthetic fuel were partially offset by lower amortization of the Tiger production, natural gas production, coal extraction and Bay regulatory asset of $2 million, which was fully terminal operations. Beginning in the fourth quarter of amortized in September 2003. 2003, the Company ceased recording portions of Fuels' segment operations, primarily synthetic fuel facilities, Taxes Other than on Income one month in arrears. As a result, earnings for the year ended December 31, 2003, included 13 months of Taxes other than on income were $254 million in 2004, operations, resulting in a net income increase of which represents an increase of $13 million compared to

$2million for the year.

the prior year. This increase is due to increases in gross 29

V Managements Discussion and Analysis The following summarizes Fuels' segment profits: the requested recovery of the storm costs, the Company's loss from the casualty is less than originally anticipated.

(inmillions) 2004 2003 2002 Accordingly, as of December 31, 2004, the Company's Synthetic fuel operations $91 S205 $156 anticipated 2004 tax liability supported credits on Natural gas operations 85 34 10 approximately eight million tons. Therefore, the Company Coal fuel and other operations 4 (4) 10 recorded tax credits of $90 million for the quarter ended Segment profits $180 S235 $176 December 31, 2004, for tax credits associated with approximately three million tons sold during the year that SYNTHETIC FUEL OPERATIONS the Company now anticipates can be used. As of December 31, 2004, the Company anticipates that The production and sale of synthetic fuel generate approximately S7 million of tax credits associated with operating losses, but qualify for tax credits under Section approximately 0.2 million tons sold during the year could 29 of the Code, which more than offset the effect of such not be used (See Note 23E). The Company ceased losses (See Note 23E). operations at its Earthco facilities for the last three months of 2004 due to the decrease in the Company's The operations resulted in the following losses (prior to projected 2004 tax liability, and these facilities were tax credits): restarted in January 2005.

tin millions) 2004 2003 2002 Tons sold 8.3 12.4 11.2 The Company believes its right to recover storm costs is After-tax losses well established; however, the Company cannot predict (excluding tax credits) $(124) S(141) S(135) the timing or outcome of this matter. If the FPSC should Tax credits 215 346 291 deny PEFs petition for the recovery of storm costs in Net profit $91 S205 $156 2005, there could be a material impact on the amount of 2005 synthetic fuel production and results of operations.

The Company's synthetic fuel production levels and the amount of tax credits it can claim each year are afunction Synthetic fuels' net profits for 2003 increased as of the Company's projected consolidated regular federal compared to 2002 due to higher sales, improved margins income tax liability. Synthetic fuel operations' net profits and a higher tax credit per ton. The 2003 tax credits also decreased in 2004 as compared to 2003 due primarilyto a include a $13 million favorable true-up from 2002.

decrease in synthetic fuel production and an increase in Additionally, synthetic fuels' results in 2003 include operating expenses in2004. The Company's total synthetic 13 months of operations for some facilities. Prior to the fuel production of approximately eight million tons in 2004 fourth quarter of 2003, results of these synthetic fuels' is down compared to 2003 production levels of operations had been recognized one month in arrears.

approximately 12 million tons as a result of hurricane The net impact of this action increased net income by costs, which reduced the Company's projected 2004 $2 million for the year.

regular tax liability and its corresponding ability to record tax credits from its synthetic fuel production. In addition, NATURAL GAS OPERATIONS earnings in 2003 include a S13 million favorable tax credit Natural gas operations generated profits of $85 million, true-up related to 2002. $34 million and $10 million for the years ended December 31, 2004, 2003 and 2002, respectively. Natural gas profits As of September 30, 2004, the Company anticipated an increased $51 million in 2004 compared to 2003. This ability to record approximately five million tons of synthetic increase is attributable primarily to the gain recognized fuel production based on the Company's projected regular on the sale of gas assets during the year. In December tax liability for 2004. This estimate was based upon the 2004, the Company sold certain gas-producing Company's projected casualty loss as a result of the properties and related assets owned by Winchester storms. Therefore, the Company recorded a charge of Production Company, Ltd. (North Texas gas operations).

$79 million in the third quarter for tax credits associated Because the sale significantly altered the ongoing with approximately 2.7 million tons sold during the year relationship between capitalized costs and remaining that the Company anticipated it would not be able to use. proved reserves, under the full-cost method of On November 2,2004, PEF filed a petition with the FPSC to accounting the pre-tax gain of S56 million ($31 million net recover $252 million of storm costs plus interest from of taxes) was recognized in earnings rather than as a customers over a two-year period. Based on a reasonable reduction of the basis of the Company's remaining oil expectation at December 31,2004, that the FPSC will grant and gas properties. In addition, an increase in 30

Progress Energy Annual Report 2004 production, coupled with higher gas prices in 2004, of $10 million in 2004. Corporate costs in the prior year contributed to the increased earnings in 2004 as included $4million of favorability related to the reduction compared to 2003. Production levels increased resulting of an environmental reserve (See Note 22). The remaining from the acquisition of North Texas Gas in late February unfavorability in corporate costs is attributable to 2003 and increased drilling in 2004. Volume and prices increased interest expense related to unresolved tax have increased 21% and 16%, respectively, for 2004 matters and higher professional fees.

compared to 2003.

Coal fuel and other operations' profits decreased Natural gas profits increased to $34 million in 2003 $9million from 2002 to 2003. The decrease is due primarily compared to $10 million in 2002. The increase in production to the recording of an impairment of certain assets at the and price resulting from the acquisitions of Westchester in Kentucky May coal mine totaling $11 million after-tax. The 2002 (renamed Winchester Energy in 2004) and NorthTexas decrease in profits is also due to the impact of the Gas inthe first quarter of 2003 drove increased revenue and retroactive Service Company allocation in 2003.

earnings in 2003 compared to 2002. In October 2003, the Company completed the sale of certain gas-producing The Company is exploring strategic alternatives regarding properties owned by Mesa Hydrocarbons, LLC (Mesa). See the Fuels' coal mining business, which could include Notes 5B and 4D to the Progress Energy Consolidated divesting these assets. As of December 31, 2004, the Financial Statements for discussions of the North Texas carrying value of long-lived assets of the coal mining Gas acquisitions and the Mesa disposition. business was $66 million. The Company cannot currently predict the outcome of this matter.

The following table summarizes the production and revenues of the natural gas operations by location: Competitive Commercial Operations 2004 2003 2002 CCO generates and sells electricity to the wholesale Production inBcf equivalent market from nonregulated plants. These operations also EastTexas/LAgasoperations 20 13 6 include marketing activities. The following summarizes North Texas gas operations 10 7 - the annual revenues, gross margin and segment profits Mesa - 5 7 from the CCO plants:

Total production 30 25 13 (inmillions) 2004 2003 2002 Revenues in millions Total revenues $240 S170 S92 EastTexaslLAgasoperations $110 $65 S24 Gross margin North Texas gas operations 52 38 - In millions ofS $158 S141 £83 Mesa - 13 15 As a %of revenues 66% 83% 90%

Total revenues $162 £116 £39 Segment profits (losses) $14) S20 £27 Gross margin Inmillions of S $126 £91 £29 CCO's operations generated segment losses of $4million in As a %of revenues 78% 78% 74% 2004 compared to segment profits of $20 million in 2003.

Results for 2004 were favorably impacted by increased gross margin, which was more than offset by higher fixed COAL FUEL AND OTHER OPERATIONS costs and costs associated with the extinguishment of Coal fuel and other operations generated profits of debt Revenues increased for 2004 due to increased

$4million, losses of $4million and profits of $10 million for revenues from marketing and tolling contracts offset by a the years ended December 31, 2004, 2003 and 2002, termination payment received on a marketing contract in respectively. The increase in profits for 2004 is primarily 2003. Expenses forthe cost of fuel and purchased powerto due to higher volumes and margins for coal fuel supply marketing contracts partially offset the increased operations of $16 million after-tax. In addition, coal revenues netting to an increase in gross margin for 2004 as results in 2003 included the recording of an impairment of compared to 2003. Fixed costs increased $16 million certain assets at the Kentucky May coal mine totaling pre-tax from additional depreciation and amortization on

$11 million after-tax. This favorability was offset by a plants placed into service in 2003 and from an increase in reduction in profits of S7 million after-tax for fuel interest expense of $13 million pre-tax due primarily to transportation operations related to the waterborne interest no longer being capitalized due to the completion transportation ruling by the FPSC (See Note 8C). Profits of construction in the prior year. In addition, plant were also negatively impacted by higher corporate costs operating expenses increased $12 million pre-tax primarily 31

V Management's Discussion and Analysis due to higher gas transportation service charges, which Revenues were $1.131 billion in 2004, which represents increased over prior year due to a full period of expenses an increase of $284 million compared to prior year. This being reflected in currentyear results. CCO results for 2004 increase is due primarily to increased volumes and also include losses of $15 million pre-tax associated with higher prices in recycling operations and in part to the extinguishment of a debt obligation. CCO terminated increased production and sales in locomotive and railcar the Genco financing arrangement in December 2004. The services and engineering and track services.Tonnage for

$15 million pre-tax loss is comprised of a $9million write- recycling operations is up approximately 35% on an off of remaining unamortized debt issuance costs and a annualized basis compared to 2003. The increase in

$6million realized loss on exiting the related interest rate tonnage, coupled with an increase in the average index hedge. Expenses were favorably impacted by a reduction price of approximately 80%, accounts for the significant in Service Company allocations. Results for 2003 were increase in revenues year over year. The American Metal negatively impacted by the retroactive reallocation of Market index price for #1 railroad heavy melt (which is Service Company costs of $3million ($2 million after-tax). used as the index for buying and selling of railcars) has increased to $191 as of December 31, 2004, from $106 as CCO's operations generated segment profits of $20 million of December 31,2003. Cost of goods sold was $990 million in 2003 compared to segment profits of $27 million in 2002. in 2004, which represents an increase of $252 million The increase in revenue for 2003 when compared to 2002 compared to the prior year. The increase in costs of is primarily due to increased contracted capacity on goods sold is due to increased costs for inventory, labor newly constructed plants, energy revenue from a new, and operations as a result of the increased volume in the full-requirements power supply contract and a tolling recycling operations, locomotive and railcar services and agreement termination payment received during the first engineering and track services. In addition, results in quarter. Generating capacity increased from 1,554 MW at 2003 were negatively impacted by the retroactive December 31, 2002, to 3,100 MW at December 31, 2003, reallocation of Service Company costs of $3million after-with the Effingham, Rowan Phase 2 and Washington tax. The favorability related to the reallocation was offset plants being placed in service in 2003. In the second by an increase in general and administrative costs in 2004 quarter of 2003, PVI acquired from Williams Energy related primarily to higher professional fees associated Marketing and Trading a full-requirements power supply with divestiture efforts. See discussion below.

agreement with Jackson Electric Membership Corporation in Georgia for $188 million, which resulted in Rail's operations generated segment losses of $1 million additional revenues of $21 million when compared to the in 2003 compared to segment losses of $42 million in 2002.

same periods in 2002. The revenue increases related to The reduction in losses in 2003 compared to 2002 is due higher volumes were partially offset by higher primarily to an impairment charge recorded in 2002. The depreciation costs of $22 million, increased interest net loss in 2002 includes a $40 million after-tax estimated charges of $16 million and other fixed charges. impairment of assets held for sale related to Railcar Ltd.,

a leasing subsidiary of Progress Rail (See Note 40).

The Company has contracts for its planned production Excluding the impairment recorded in 2002, profits for Rail capacity, which includes callable resources from the were flat year over year 2003 compared to 2002.

cooperatives, of approximately 77% for 2005, approximately 81% for 2006 and approximately 75% for In February 2005, Progress Energy signed a definitive 2007. The Company continues to seek opportunities to agreement to sell its Progress Rail subsidiary to optimize its nonregulated generation portfolio. subsidiaries of One Equity Partners LLC for a sales price of $405 million. Proceeds from the sale are expected to be Rail Services used to reduce debt. See Note 24 for more information.

Rail Services' (Rail) operations represent the activities of Corporate & Other Progress Rail and include railcar and locomotive repair, track-work, rail parts reconditioning and sales, scrap metal Corporate and Other consists of the operations of recycling, railcar leasing and other rail-related services. Progress Energy Holding Company (the holding company), Progress Energy Service Company and other Rail contributed segment profits of $16 million for 2004 consolidating and nonoperating entities. Corporate and compared with segment losses of $1 million and Other also includes other nonregulated business

$42 million for the years ended December 31, 2003, and areas including the operations of SRS and the 2002, respectively. Results in 2004 were favorably telecommunication operations.

impacted by the strong scrap metal market in 2004.

32

Progress Energy Annual Report 2004 OTHER NONREGULATED BUSINESS AREAS Other nonregulated business areas contributed segment losses of $24 million in 2003 compared to $250 million for Progress Energy's other business areas include the the year ended December 31, 2002. The 2002 segment operations of SRS and the telecommunications losses include an asset impairment and other charges in operations. SRS was engaged in providing energy the telecommunications business of $225 million after-services to industrial, commercial and institutional tax. See discussion of impairments at Note 10 of the customers to help manage energy costs primarily in the Consolidated Financial Statements.

southeastern United States. During 2004, SRS sold its subsidiary, Progress Energy Solutions (PES). With the CORPORATE SERVICES disposition of PES, the Company exited this business area. Telecommunication operations provide broadband Corporate Services (Corporate) includes the operations of capacity services, dark fiber and wireless services in the holding company, Progress Energy Service Company Florida and the eastern United States. In December 2003, and other consolidating and nonoperating entities, as PTC and Caronet, both wholly owned telecommunication summarized below:

subsidiaries of Progress Energy, and EPIK, a wholly Income (Expense) (inmillions) owned subsidiary of Odyssey, contributed substantially 2004 Change 2003 Change 2002 all of their assets and transferred certain liabilities to PT LLC, a subsidiary of PTC. The accounts of PT LLC have Other interest expense $1270) $15 S(285) S$IO) S(275) been included in the Company's Consolidated Financial Contingent value Statements since the transaction date. See additional obligations 9 18 (9) (37) 28 discussion on the telecommunication business Tax reallocation (37) 1 (38) 18 (56) combination in Note 5A. Otherincometaxes 102 (22) 124 11 113 Other income Other nonregulated business areas contributed segment (expense) (2) 19 (21) (16) 15) losses of $38 million compared to losses of $24 million for Segment loss $1198) $31 $(229) S134) S(195) the years ended December 31, 2004, and 2003, respectively. SRS recorded a net loss of $27 million for 2004 compared to a net loss of S6 million for 2003. The The other interest expense decrease for 2004 compared to increased loss compared to the prior year is due primarily 2003 is partially due to the repayment of a $500 million to the recording of the litigation settlement reached with unsecured note by the Holding Company on March 1,2004, San Francisco United School District (the District) related which reduced interest expense by $27 million pre-tax for to civil proceedings. In June 2004, SRS reached a 2004. This reduction was offset by interest no longer being settlement with the District that settled all outstanding capitalized due to the completion of construction in the claims for approximately $43 million pre-tax ($29 million CCO segment in 2003. Approximately$10 million ($6 million after-tax). The reduction in earnings due to the settlement after-tax) was capitalized in 2003. No interest expense was was offset partially by a gain recognized on the sale of capitalized during 2004. Interest expense increased Progress Energy Solutions. Telecommunication $10 million in 2003 compared to 2002 due to a decrease of operations recorded a net loss of $5 million in 2004 $9 million in the amount of interest capitalized related to compared to a net profit of $2 million in 2003. The the construction of plants by CCO which was completed increase in losses compared to prior year is due to an in 2003.

increase in fixed costs, mainly depreciation expense, and professional fees related to the merger with EPIK. The Progress Energy issued 98.6 million contingent value increased losses at SRS and telecommunication obligations (CVOs) in connection with the acquisition of operations were offset partially by a reduction in losses FPC in 2000. Each CVO represents the right to receive at the nonutility subsidiaries of PEC. The nonutility contingent payments based on the performance of four subsidiaries of PEC contributed segment losses of synthetic fuel facilities owned by Progress Energy. The

$6 million and $18 million for the years ended December payments, if any, are based on the net after-tax cash 31, 2004, and 2003, respectively. Included in the 2003 flows the facilities generate. At December 31, 2004, 2003 segment losses is an investment impairment of $6million and 2002, the CVOs had a fair market value of after-tax on the Affordable Housing portfolio held by the approximately $13 million, $23 million and $14 million, nonutility subsidiaries of PEC (See Note 10B). A reduction respectively. Progress Energy recorded unrealized in investment losses accounted for the remaining losses of S9 million for 2003 and an unrealized gain of favorability compared to prior year. $9million and $28 million for 2004 and 2002, respectively, to record the changes in fair value of CVOs, which 33

V Management's Discussion and Analysis had average unit prices of SO.14, $0.23 and $0.14 at recorded at its fair value. PEC Electric had a purchase December 31, 2004, 2003 and 2002, respectively. power contract with Broad River LLC that did not meet the criteria for an exception, and a negative fair value Progress Energy and its affiliates file a consolidated adjustmentwas recorded in 2003for$23 million after-tax federal income tax return. The consolidated income tax of (See Note 18A).

Progress Energy is allocated to subsidiaries in accordance with the Intercompany Income Tax Allocation APPLICATION OF CRITICAL ACCOUNTING Agreement (Tax Agreement). The Tax Agreement POLICIES AND ESTIMATES provided an allocation that recognizes positive and The Company prepared its Consolidated Financial negative corporate taxable income. The Tax Agreement Statements in accordance with accounting principles provides for an equitable method of apportioning the carry generally accepted in the United States. In doing so, over of uncompensated tax benefits. Progress Energy tax certain estimates were made that were critical in nature benefits not related to acquisition interest expense are to the results of operations. The following discusses allocated to profitable subsidiaries, beginning in 2002, in those significant estimates that may have a material accordance with a Public Utility Holding Company Act of impact on the financial results of the Company and are 1935, as amended (PUHCA) order. subject to the greatest amount of subjectivity. Senior management has discussed the development and Other income taxes benefit decreased for 2004 compared selection of these critical accounting policies with the to 2003 due primarily to increased taxes booked at the Audit Committee of the Company's Board of Directors.

Holding Company of $21 million. Income taxes increased an additional $9 million at the Holding Company as a result of a reserve booked related to identified state tax Utility Regulation deficiencies. Other income taxes benefit decreased for As discussed in Note 8,the Company's regulated utilities 2003 compared to 2002 primarily for the tax allocation to segments are subject to regulation that sets the prices the profitable subsidiaries. Other fluctuations in income (rates) the Company is permitted to charge customers taxes are primarily due to changes in pre-tax income. based on the costs that regulatory agencies determine the Company is permitted to recover. At times, regulators Discontinued Operations permit the future recovery through rates of costs that would be currently charged to expense by a In 2002, the Company approved the sale of NCNG to nonregulated company. This rate-making process results Piedmont Natural Gas Company, Inc. As a result, the in deferral of expense recognition and the recording of operating results of NCNG were reclassified to regulatory assets based on anticipated future cash discontinued operations for all reportable periods. In inflows. As a result of the changing regulatory framework September 2003, Progress Energy completed the sale of NCNG and ENCNG for net proceeds of approximately in each state in which the Company operates, a significant amount of regulatory assets has been

$450 million in September 2003. Progress Energy incurred recorded. The Company continually reviews these assets a loss from discontinued operations of $8million for 2003 to assess their ultimate recoverability within the compared with a loss of $24 million for 2002. During the approved regulatory guidelines. Impairment risk year ended December 31, 2004, the Company recorded a associated with these assets relates to potentially reduction to the loss on the sale of NCNG of approximately adverse legislative, judicial or regulatory actions in the

$6million related to deferred taxes (See Note 4E).

future. Additionally, the state regulatory agencies often provide flexibility in the manner and timing of the Cumulative Effect of Accounting Changes depreciation of property, nuclear decommissioning costs In 2003, Progress Energy recorded adjustments for the and amortization of the regulatory assets. Note 8 cumulative effects of changes in accounting principles provides additional information related to the impact of due to the adoption of several new accounting utility regulation on the Company.

pronouncements. These adjustments totaled to a S21 million loss after-tax,which was due primarily to new Asset Impairments Financial Accounting Standards Board (FASB) guidance As discussed in Note 10, the Company evaluates the related to the accounting for certain contracts. This carrying value of long-lived assets for impairment guidance discusses whether the pricing in a contract whenever indicators exist. Examples of these indicators that contains broad market indices qualifies for certain include current period losses combined with a history of exceptions that would not require the contract to be 34

Progress Energy Annual Report 2004 losses, or a projection of continuing losses, or a net revenues using current prices, plus the lower of cost significant decrease in the market price of a long-lived or fair market value of unproved properties. The ceiling asset group. If an indicator exists, the asset group held test takes into consideration the prices of qualifying cash and used is tested for recoverability by comparing the flow hedges as of the balance sheet date. If the ceiling carrying value to the sum of undiscounted expected (discounted revenues) isnot equal to or greater than total future cash flows directly attributable to the asset group. capitalized costs, the Company is required to write-down If the asset group is not recoverable through capitalized costs to this level. The Company performs this undiscounted cash flows or if the asset group is to be ceiling test calculation every quarter. No write-downs disposed of, an impairment loss is recognized for the were required in 2004, 2003 or 2002.

difference between the carrying value and the fair value of the asset group. A high degree of judgment is required Goodwill in developing estimates related to these evaluations and As discussed in Note 9, effective January 1, 2002, the various factors are considered, including projected Company adopted FASB Statement No. 142, 'Goodwill revenues and cost and market conditions. and Other Intangible Assets,' which requires that goodwill be tested for impairment at least annually and Due to the reduction in coal production at the Kentucky more frequently when indicators of impairment exist The May coal mine, the Company evaluated its long-lived Company completed the initial transitional goodwill assets in 2003 and recorded an impairment of $17 million impairment test, which indicated that the Company's before tax ($11 million after-tax). Fair value was goodwill was not impaired as of January 1, 2002. The determined based on discounted cash flows. During Company performed the annual goodwill impairment test 2002, the Company recorded pre-tax long-lived asset for the CCO segment inthe first quarters of 2004 and 2003, impairments of $305 million related to its and the annual goodwill impairment test for the PEC telecommunications business. The fair value of these Electric and PEF segments in the second quarters of 2004 assets was determined considering various factors, and 2003, each of which indicated no impairment If the including a valuation study heavily weighted on a fair values for the utility segments were lower by discounted cash flow methodology and using market approximately 10%, there still would be no impact on the approaches as supporting information. reported value of their goodwill. The carrying amounts of goodwill at December 31, 2004, and 2003, for reportable The Company continually reviews its investments to segments PEC Electric, PEF and CCO, are $1,922 million, determine whether a decline in fair value below the cost

$1,733 million and $64 million, respectively. In December basis is other than temporary. In 2003, PEC's affordable 2003, $7 million in goodwill was acquired as part of housing investment (AHI) portfolio was reviewed and Progress Telecommunications Corporation's partial deemed to be impaired based on various factors, acquisition of EPIK and was reported in the Corporate including continued operating losses of the AHI portfolio and Other segment The Company revised the preliminary and management performance issues arising at certain EPIK purchase price allocation as of September 2004, properties within the AHI portfolio. As a result, PEC and the $7million of goodwill was reallocated to certain recorded an impairment of $18 million on a pre-tax basis tangible assets acquired based on the results of during 2003. PEC also recorded an impairment of valuations and appraisals.

$3million for a cost investment During 2002, the Company recorded pre-tax impairments to its cost method investment in Interpath of $25 million. The fair value of this Synthetic Fuels Tax Credits investment was determined considering various factors, As discussed in Note 23E, Progress Energy, through the including a valuation study heavily weighted on a Fuels business unit, owns facilities that produce discounted cash flow methodology and using market synthetic fuels as defined under the Internal Revenue approaches as supporting information. These cash flows Code. The production and sale of the synthetic fuels from included numerous assumptions, including the pace at these facilities qualifies for tax credits under Section 29 which the telecommunications market would rebound. In if certain requirements are satisfied, including a the fourth quarter of 2002, the Company sold its remaining requirementthatthe synthetic fuels differs significantlyin interest in Interpath for a nominal amount chemical composition from the coal used to produce such synthetic fuels and that the fuel was produced Under the full-cost method of accounting for oil and gas from a facility placed in service before July 1, 1998. The properties, total capitalized costs are limited to a ceiling amount of Section 29 credits thatthe Company is allowed based on the present value of discounted (at 10%) future to claim in any calendar year is limited by the amount of 35

V Management's Discussion and Analysis the Company's regular federal income tax liability. assets is 9.25%. The Company reviews this rate on a Synthetic fuels tax credit amounts allowed but not regular basis. Under Statement of Financial Accounting utilized are carried forward indefinitely as deferred Standards No. 87, 'Employer's Accounting for Pensions' alternative minimum tax credits on the Consolidated (SFAS No. 87), the expected rate of return used in Balance Sheets. All of Progress Energy's synthetic fuel pension cost recognition is a long-term rate of return; facilities have received PLRs from the IRS with respectto therefore, the Company would adjust that return only if their operations, although these do not address placed- its fundamental assessment of the debt and equity in-service date determinations. The PLRs do not limit the markets changes or its investment policy changes production on which synthetic fuel credits may be significantly. The Company believes that its pension claimed. The current Section 29 tax credit program plans' asset investment mix and historical performance expires at the end of 2007. These tax credits are subject support the long-term rate of 9.25% being used. The to review by the IRS, and if Progress Energy fails to Company did not adjust the rate in response to short-prevail through the administrative or legal process, there term market fluctuations such as the abnormally high could be a significant tax liability owed for previously market return levels of the latter 1990s, recent years' taken Section 29 credits, with a significant impact on market declines and the market rebound in 2003 and earnings and cash flows. Additionally, the ability to use 2004. A 0.25% change in the expected rate of return for tax credits currently being carried forward could be 2004 would have changed 2004 pension costs by denied. See further discussion in "OTHER MATTERS' approximately $4 million.

below, and Note 23E.

Another factor affecting the Company's pension costs, Pension Costs and sensitivity of the costs to plan asset performance, is its selection of a method to determine the market-related As discussed in Note 17A, Progress Energy maintains value of assets, i.e., the asset value to which the 9.25%

qualified noncontributory defined benefit retirement expected long-term rate of return is applied. SFAS No. 87 (pension) plans. The Company's reported costs are specifies that entities may use either fair value or an dependent on numerous factors resulting from actual averaging method that recognizes changes in fair value plan experience and assumptions of future experience.

over a period not to exceed five years, with the method For example, such costs are impacted by employee selected applied on a consistent basis from year to year.

demographics, changes made to plan provisions, actual The Company has historically used a five-year averaging plan asset returns and key actuarial assumptions, such method. When the Company acquired Florida Progress as expected long-term rates of return on plan assets and Corporation (Florida Progress) in 2000, it retained the discount rates used in determining benefit obligations Florida Progress historical use of fair value to determine and annual costs.

market-related value for Florida Progress pension assets. Changes in plan asset performance are reflected Due to a slight decline in the market interest rates for in pension costs soonerunderthe fairvalue method than high-quality (AAIAA) debt securities, which are used the five-year averaging method, and, therefore, pension as the benchmark for setting the discount rate used to costs tend to be more volatile using the fair value present value future benefit payments, the Company method. For example, in 2004 the expected return for lowered the discount rate to 5.9% at December 31, 2004, assets subject to the averaging method was 2%lower which will increase the 2005 benefit costs recognized, all than in 2003, whereas the expected return for assets other factors remaining constant. Plan assets performed subject to the fair value method was 24% higher than in well in 2004, with returns of approximately 14%. That 2003. Approximately 50% of the Company's pension plan positive asset performance will result in decreased assets is subjectto each of the two methods.

pension costs in 2005, all other factors remaining constant. Evaluations of the effects of these and other factors have not been completed, but the Company LIQUIDITY AND CAPITAL RESOURCES estimates that the total cost recognized for pensions in 2005 will be approximately $12 million to $20 million Overview higher than the amount recorded in 2004. Progress Energy is a registered holding company and, as such, has no operations of its own. The Company's primary The Company has pension plan assets with a fair value cash needs at the holding company level are its common of approximately $1.8 billion at December 31, 2004. The stock dividend and interest expense and principal Company's expected rate of return on pension plan payments on its S4.3 billion of senior unsecured debt The 36

Progress Energy Annual Report 2004 ability to meet these needs is dependent on the earnings Historical for 2004 as compared to 2003 and 2003 as and cash flows of its two electric utilities and nonregulated compared to 2002 subsidiaries, and the ability of those subsidiaries to pay Cash Flows from Operations dividends or repay funds to Progress Energy.

Cash from operations is the primary source used to meet Other significant cash requirements of the Company arise operating requirements and capital expenditures. Net primarily from the capital-intensive nature of its electric cash provided by operating activities from continuing utility operations and expenditures for its diversified operations forthe three years ending December31, 2004, businesses, primarily those of the Fuels segment. 2003 and 2002 were $1.6 billion, $1.7 billion and

$1.6 billion, respectively.

The Company relies upon its operating cash flow, primarily generated by its two regulated electric utility Cash from operating activities for 2004 when compared subsidiaries, commercial paper and bank facilities, and with 2003 decreased $117 million, as the net result of the its ability to access long-term debt and equity capital impact of hurricane costs, partially offset bythe impact of markets for sources of liquidity. an underrecovery of fuel costs in 2003. The increase in cash from operating activities for 2003 when compared The majority of the Company's operating costs are related with 2002 is largely the result of improved operating to its two regulated electric utilities, and a significant results at PEC.

portion of these costs is recovered from customers through fuel and energy cost recovery clauses. During the third quarter of 2004, four hurricanes struck significant portions of the Company's service territories, Other significant uses of liquid resources include debt with the most significant impact on PEFs territory.

interest and principal payments, capital expenditures and Restoration of the Company's systems from storm-related dividends on preferred and common stock. damage cost an estimated $398 million. PEC's costtotaled

$13 million, of which $12 million was charged to O&M and As a registered holding company under PUHCA, $1 million was charged to capital. PEFs cost totaled Progress Energy obtains approval from the SEC for the $385 million, of which S338 million was charged to Storm issuance and sale of securities as well as the Damage Reserve pursuant to a regulatory order and establishment of intercompany extensions of credit $47 million was charged to capital. On November 2, 2004, (utility and nonutility money pools). PEC and PEF PEF filed a petition with the FPSC to recover $252 million participate in the utility money pool, which allows the of storm costs plus interest from retail rate payers over a two utilities to lend and borrow between each other. A two-year period (See Note 3).

nonutility money pool allows Progress Energy's nonregulated operations to lend and borrow funds Progress Energy is allowed to recover fuel costs incurred among each other. Progress Energy can lend money to by PEC and PEF through their respective fuel cost the utility and nonutility money pools but cannot borrow recovery surcharges. Fuel price volatility can lead to over-funds. or underrecovery of fuel costs, as changes in fuel prices are not immediately reflected in fuel surcharges due to Cash from operations, asset sales and the issuance of regulatory lag in setting the surcharges. As a result, fuel common stock are expected to fund capital expenditures price volatility can be both a source of and a drag on and common dividends for 2005. Any excess cash liquidity resources, depending on what phase of the cycle proceeds would be used to reduce debt To the extent of price volatility the Company isexperiencing. In addition, necessary, short- and long-term debt may also be used in 2004 PEF agreed with the FPSC to use atwo-year period as a source of liquidity. to determine the surcharge for the underrecovered fuel costs incurred in 2004 (See Note 8C).

The Company believes its internal and external liquidity resources will be sufficient to fund its current Investing Activities business plans. Net cash used in investing activities for the three years ending December 31, 2004, 2003 and 2002 were The following discussion of the Company's liquidity and $0.9 billion, $1.5 billion and $2.2 billion, respectively.

capital resources is on a consolidated basis.

37

V Management's Discussion and Analysis Utility property additions for the Company's regulated During 2002, the Company purchased two electric electric operations were $1.0 billion or approximately 75% generation projects for a cash purchase price of of consolidated capital expenditures in 2004 and $348 million.

$1.0 billion or approximately 58% of consolidated capital expenditures in 2003, excluding proceeds from asset sales. Financing Activities Capital expenditures for the regulated electric operations Net cash provided by financing activities for the three are primarily for normal construction activity and ongoing years ending December 31, 2004, 2003 and 2002 were capital expenditures related to environmental compliance $(720) million, $4192) million and S581 million, respectively.

programs. Capital expenditures for the nonregulated See Note 13 for details of debt and credit facilities.

operations are primarily for natural gas development activities and normal construction activity. For 2004 and 2003, cash from operations exceeded net cash used in investing activities by $735 million and $178 million, Excluding proceeds from sales of subsidiaries and other respectively, due primarily to asset sales, which allowed investments, cash used in investing activities decreased for a net decrease in cash provided by financing activities.

approximately $887 million in 2004 when compared with For 2002, net cash used in investing activity exceeded cash 2003.The decrease is due primarilytothe acquisition of a from operations by $574 million, which resulted in net cash nonregulated generation contract and acquisition of gas from financing activities of $581 million.

assets in 2003 and net proceeds from short-term investments in 2004, compared to net purchases of short- In addition to the financing activities discussed under term investments in 2003. Overview,' the financing activities of the Company included:

Excluding proceeds from sales of subsidiaries and other 2005 investments, cash used in investing activities was

$2.1 billion in 2003, down approximately $119 million when

• In March 2005, Progress Energy, Inc.'s five-year credit compared with 2002. The decrease is due primarily to facility was amended to increase the maximum total lower utility property additions due to completion of debt to total capital ratio from 65% to 68% in Hines 2 construction at PEF and lower acquisitions of anticipation of the potential impacts of proposed nonregulated assets. accounting rules for uncertain tax positions. See Notes 2 and 23E.

During 2004, sales of subsidiaries and other investments

• On January31, 2005, Progress Energy, Inc. entered into primarily included proceeds from the sale of Railcar Ltd. a new $600 million revolving credit agreement, which assets of approximately S75 million and proceeds of expires December 30, 2005. This facility was added to approximately $251 million related to the sale of natural provide additional liquidity during 2005 due in part to gas assets in the Forth Worth basin of Texas. Progress the uncertainty of the timing of storm restoration cost Energy used the proceeds from these sales to reduce recovery from the hurricanes in Florida during 2004.

indebtedness, including $241 million to pay off the The credit agreement includes a defined maximum Progress Genco Ventures, LLC, bank facility. total debt to total capital ratio of 68% and a minimum interest coverage ratio of 2.5 to 1. The credit During 2003, the Company realized approximately agreement also contains various cross-default and

$450 million of net cash proceeds from the sale of NCNG other acceleration provisions. On February 4, 2005, and ENCNG. The Company also received net proceeds $300 million was drawn under the new facility to of approximately $97 million in October 2003 for the reduce commercial paper and pay off the remaining sale of its Mesa gas properties in Colorado. Progress amount of RCA loans outstanding.

Energy used the proceeds from these sales

• InJanuary 2005, the Company used proceeds from the to reduce indebtedness, primarily commercial paper, issuance of commercial paper to pay off $260 million of then outstanding. revolving credit agreement (RCA) loans.

During 2003, the Company acquired approximately 200 natural gas-producing wells for a cash purchase price 2004 of $168 million. The Company also acquired a long-term

• During the fourth quarter of 2004, Progress Energy and full-requirements powersupply agreementwith Jackson its subsidiaries PEC and PEF borrowed a net total of Electric Membership Corporation for a cash payment of $475 million under certain revolving credit facilities.

$188 million. The borrowed funds were used to pay off maturing 38

Progress Energy Annual Report 2004 commercial paper and for other cash needs. A

• On February 9, 2004, Progress Capital Holdings, Inc.,

summary of RCA loans and available capacity as of paid at maturity $25 million 6.48% medium-term notes December 31, 2004 is as follows: with available cash from operations.

(inmillions)

• On January 15, 2004, PEC paid at maturity $150 million Company Description Total Outstanding Available 5.875% First Mortgage Bonds with commercial paper proceeds. On April 15, 2004, PEC also paid at maturity Progress Energy. 5-Year Inc. (expiring 8/MM09) S1,130 S160 $970

$150 million 7.875% First Mortgage Bonds with Progress Energy 364-Day commercial paper proceeds and cash from operations.

Carolinas, Inc. (expiring 7/27/05) 165 90 75

• For 2004, the Company issued approximately 1 million Progress Energy 3-Year shares of its common stock for approximately Carorinas, Inc. (expiring 7/31/05) 285 - 285 $73 million in net proceeds from its Investor Plus Stock Progress Energy 364-Day Purchase Plan and its employee benefit and stock Florida, Inc. (expiring 3/29/05) 200 170 30 option plans, net of purchases of restricted shares. For Progress Energy 3-Year Florida, Inc. (expiring 4/01/06) 200 55 145 2004, the dividends paid on common stock were Less: amounts approximately $558 million.

reservedla) - - (574)

Total credit 2003 facilities $1,980 $475 $931

{alTo the extent amounts are reserved for commercial paper outstanding or

• Progress Energy obtained a three-year financing backing letters of credit they are not available for additional borrowings. order, allowing it to issue up to $2.8 billion of long-term securities, $1.5 billion of short-term debt, and $3billion

• On December 17, 2004, the Company used proceeds in parent guarantees. Progress Energy issued from the sale of natural gas assets to extinguish approximately 8 million shares of common stock for Progress Genco Ventures, LLC's $241 million bank approximately $304 million in net proceeds from its facility (See Note 13D). Investor Plus Stock Purchase Plan and its employee

• Progress Energy took advantage of favorable market benefit plans, net of purchases of restricted shares.

conditions and entered into a new $1.1 billion five-year For 2003, the dividends paid on common stock were line of credit, effective August 5, 2004, and expiring approximately$541 million.

August 5,2009. This facility replaced Progress Energy's

• PEC redeemed $250 million and issued $600 million in

$250 million 364-day line of credit and its three-year first mortgage bonds.

$450 million line of credit, which were both scheduled

• PEF redeemed $250 million, issued $950 million and paid to expire in November 2004. at maturity$180 million in first mortgage bonds. PEF also

• On July 28, 2004, PEC extended its $165 million 364-day paid at maturity $35 million in medium-term notes.

line of credit, which was scheduled to expire on

• Progress Capital Holdings, Inc., paid at maturity July 29,2004.The line of creditwill expire on July27,2005. $58 million in medium-term notes.

• On July 1,2004, PEF paid at maturity $40 million 6.69%

• Progress Genco Ventures, LLC, terminated its Medium-Term Notes Series B with commercial paper $50 million working capital credit facility. Under its proceeds and cash from operations. related construction facility, Genco had drawn

• On April 30,2004, PEC redeemed $35 million of Darlington $241 million at December 31, 2003.

County 6.6% Series Pollution Control Bonds at 102.5% of par, $2 million of New Hanover County 6.3% Series 2002 Pollution Control Bonds at 101.5% of par, and $2million of

• Progress Energy issued $800 million in senior unsecured Chatham County 6.3% Series Pollution Control Bonds at 101.5% of par with cash from operations. notes. Progress Energy issued approximately 2 million shares representing approximately $86 million in

• On March 1, 2004, Progress Energy used available proceeds from its Investor Plus Stock Purchase Plan cash and proceeds from the issuance of commercial and its employee benefit plans.

paper to pay at maturity $500 million 6.55% senior

• PEC issued and redeemed $500 million in senior unsecured notes. Cash and commercial paper unsecured notes and $48.5 million in pollution control capacity for this retirement was created primarily from proceeds of the sale of assets in 2003. obligations. PEC also redeemed $150 million and paid at maturity $100 million in first mortgage bonds.

39

V Management's Discussion and Analysis

• PEF issued and redeemed S241 million in pollution Capital Expenditures control obligations and paid at maturity $30 million in medium-term notes. Total cash from operations provided the funding for the Company's capital expenditures, including property

• Progress Capital Holdings, Inc., paid at maturity additions, nuclear fuel expenditures and diversified

$50 million in medium-term notes. business property additions during 2004, excluding

• Progress Genco Ventures, LLC, obtained a $440 million proceeds from asset sales of $366 million.

bank facility, including $50 million for working capital. During the year, $130 million of the facility As shown in the table below, Progress Energy expects was terminated. The amount outstanding at the majority of its capital expenditures to be incurred at December 31, 2002, was $225 million. its regulated operations. See Note 8F for adiscussion of

• In November 2002, the Company issued 14.7 million expected impacts on future capital expenditures due to shares of common stock for net cash proceeds of changes in capitalization practice for regulated approximately $600 million, which were primarily used operations. The Company anticipates its regulated to retire commercial paper. For 2002, the dividends paid capital expenditures will increase in 2005 due to on common stock were approximately $480 million. increased spending on Clean Air initiatives. Forecasted nonregulated expenditures relate primarily to Progress Future liquidity and capital resources Fuels and its gas operations, mainly for drilling new wells.

The Company's two electric utilities produced over 100% Actual Forecasted

[in millions) 2004 2005 2006 2007 of consolidated cash from operations in 2004. It is expected that the two electric utilities will continue to Regulated capital expenditures S998 $1,030 $1,040 $1,090 produce a majority of the consolidated cash flows from Nuclear fuel expenditures 101 120 90 150 operations overthe next several years as its nonregulated AFUOC-borrowed funds (6) (10) (10) (10) investments, primarily generation assets, improve asset Nonregulated capital utilization and increase their operating cash flows. expenditures 236 190 180 190 Total $1,329 $1,330 $1,300 $1,420 PEF notified the FPSC in January 2005 of its intentto file for an increase in its base rates effective January 1,2006. If approved by the FPSC, an increase in PEF's base rates Regulated capital expenditures in the table above would increase future operating cash flows. PEF has include total expenditures from 2005 through 2006 of faced significant costincreases overthe past decade and approximately$65 million expected to be incurred at PEC expects its operational costs to continue to increase. fossil-fueled electric generating facilities to comply with These costs include the costs associated with completion Section 110 of the Clean Air Act, referred to as the NOx of the Hines 3 generation facility, extraordinary hurricane SIP Call.

damage costs including capital costs not expected to be directly recoverable, the need to replenish the depleted The Company also expects to incur expenditures of storm reserve and the expected infrastructure investment approximately $15 million (S10 million at PEC and necessary to meet high customer expectations, coupled $5 million at PEF) from 2005 through 2007 and additional with the demands placed on PEF as a result of strong expenditures of approximately $70 million to $100 million customer growth. If the FPSC does not approve PEF's ($10 million to S20 million at PEC and $60 million to request to increase base rates, the Company's results of $80 million at PEF) from 2008 through 2009 for compliance operations and financial condition could be negatively with the Section 316(b) requirements of the Clean Water impacted. The Company cannot predict the outcome of Act (See Note 22).

this matter.

In June 2002, legislation was enacted in North Carolina In addition, Fuels' synthetic fuel operations do not requiring the state's electric utilities to reduce the currently produce positive operating cash flow due to emissions of nitrogen oxide (NOx) and sulfur dioxide the difference in timing of when tax credits are (SO2) from coal-fired power plants. PEC expects its recognized for financial reporting purposes and when capital costs to meet these emission targets will be tax credits are realized for tax purposes. See Note 23E approximately $895 million by 2013. For the years 2005 for further discussion. through 2007, the Company expects to incur approximately $475 million of total capital costs 40

Progress Energy Annual Report 2004 associated with this legislation, which is included in the reserved for backing of letters of credit and an additional table above (See Note 22). $475 million drawn directly from the credit facilities, leaving $931 million available for issuance or drawdown.

All projected capital and investment expenditures are In addition, the Company has requirements to pay subject to periodic review and revision and may vary minimal annual commitment fees to maintain its credit significantly depending on a number of factors including, facilities. At December 31, 2003, the Company had but not limited to, industry restructuring, regulatory $4 million of commercial paper outstanding. The constraints, market volatility and economic trends. Company expects to continue to use commercial paper issuances as a source of liquidity as long as it maintains Other Cash Needs its current short-term ratings.

As of December 31, 2004, on a consolidated basis, the All of the credit facilities include a defined maximum Company had $349 million of long-term debt maturing in total debt-to-total capital ratio (leverage) and coverage 2005. Progress Energy expects to pay these maturities ratios. The Company is in compliance with these using funds from operations, issuance of new long-term covenants at December 31, 2004. See Note 13 for a debt, commercial paper borrowings and/or issuance of discussion of the credit facilities' financial covenants, new equity securities. material adverse change clause provisions and cross-default provisions. At December 31, 2004, the calculated In 2006, $800 million of Progress Energy senior ratios for the companies, pursuant to the terms of the unsecured notes will mature. The Company expects to agreements, are as disclosed in Note 13.

fund the maturity using proceeds from the sale of the Progress Rail subsidiary, issuance of new long-term Both PEC and PEF plan to enter into new five-year lines debt, commercial paper borrowings and/or issuance of of credit in 2005 to replace their existing credit facilities.

new equity securities.

The Company has on file with the SEC a shelf registration During the fourth quarter of 2004, Progress Energy statement under which senior notes, junior debentures, announced the launch of a new cost-management common and preferred stock and other trust preferred initiative aimed at achieving nonfuel O&M expense securities are available for issuance by the Company.

reductions of $75 million to $100 million annually by the At December 31, 2004, the Company had approximately end of 2007. In connection with this cost-management $1.1 billion available under this shelf registration.

initiative, the Company expects to incur one-time pre-tax charges of approximately $130 million. Approximately Progress Energy and PEF each have an uncommitted

$30 million of that amount relates to payments for bank bid facility authorizing each of them to borrow and severance benefits, which will be recognized in the first reborrow, and have loans outstanding at any time, up to quarter of 2005 and paid over time. The remaining $300 million and $100 million, respectively. At approximately $100 million will be recognized in the December 31, 2004, there were no outstanding loans second quarter of 2005 and relates primarily to against these facilities.

postretirement benefits that will be paid over time to those eligible employees who elect to participate in the PEC currently has on file with the SEC a shelf registration voluntary enhanced retirement program (See Note 24). statement under which it can issue up to $900 million of various long-term securities. PEF currently has on Credit Facilities file registration statements under which it can issue At December 31, 2004, the Company and its subsidiaries an aggregate of $750 million of various long-term had committed lines of credit and outstanding balances debt securities.

as shown inthe table in Note 13. All of the creditfacilities supporting the credit were arranged through a Both PEC and PEF can issue First Mortgage Bonds under syndication of financial institutions. There are no their respective First Mortgage Bond indentures. At bilateral contracts associated with these facilities. December 31, 2004, PEC and PEF could issue up to

$2.9 billion and $3.7 billion, respectively, based on The Company's financial policy precludes issuing property additions and S2.2 billion and $176 million, commercial paper in excess of its supporting lines of respectively, based upon retirements.

credit. At December 31, 2004, the Company had

$424 million of commercial paper outstanding, $150 million 41

V Management's Discussion and Analysis The following table shows Progress Energy's capital However, the Company monitors its financial condition as structure at December31: well as market conditions that could ultimately affect its credit ratings.

2004 2003 Common stock 41.7% 40.5% On February 11, 2005, Moody's credit rating agency Preferred stock and minority interest 0.7% 0.7% announced that it lowered the ratings of PEF, Progress Total debt 57.6% 58.8% Capital Holdings and FPC Capital Trust I and changed their rating outlooks to stable from negative. Moody's affirmed The amount and timing of future sales of company the ratings of Progress Energy and PEC.The rating outlooks securities will depend on market conditions, operating continue to be stable at PEC and negative at Progress cash flow, asset sales and the specific needs of the Energy. Moody's stated that it took this action primarily due Company. The Company may from time to time sell to declining cash flow coverages and rising leverage, securities beyond the amount needed to meet capital higher O&M costs, uncertainty regarding the timing of requirements in orderto allowforthe early redemption of hurricane cost recovery, regulatory risks associated with long-term debt, the redemption of preferred stock, the the upcoming rate case in Florida and ongoing capital reduction of short-term debt or for other general requirements to meet Florida's growing demand.

corporate purposes.

On October 19, 2004, S&P changed Progress Energy's outlook from stable to negative. S&P cited the uncertainties Credit Rating Matters regarding the timing of the recovery of hurricane costs, the The major credit rating agencies have currently rated the Company's debt reduction plans and the IRS audit of the Company's securities as follows: Company's Earthco synthetic fuels facilities as the reasons for the change in outlook. On October 25, 2004, S&P Moods Standard & Fitch reduced the short-term debt rating of Progress Energy, PEC Investors Senice Poor's Ratings and PEF to A-3 from A-2, as a result of their change in Progress Energy, Inc. outlook discussed above.

Outlook Negative Negative Stable Corporate credit rating n/a BBB n/a On October 20, 2004, Moody's changed its outlook for Senior unsecured debt Baa2 BBB- BBB- Progress Energy from stable to negative and placed the Commercial paper P-2 A-3 n/a ratings of PEF under review for possible downgrade.

Progress Energy Carolinas, Inc. PEC's ratings were affirmed by Moody's.

Corporate credit rating n/a BBB n/a Commercial paper P-2 A-3 F2 Moody's cited the following reasons for its change in the outlook for Progress Energy- financial ratios that are weak Senior secured debt A3 BBB A-for its current rating category; rising O&M, pension, Senior unsecured debt Baal BBB BBB+

benefit and insurance costs; and delays in executing its Progress Energy Florida. Inc. deleveraging plan. With respect to PEF, Moody's cited Corporate credit rating n/a BBB n/a declining cash flow coverages and rising leverage over Commercial paper P-2 A-3 F2 the last several years, expected funding needs for a large Senior secured debt A2 BBB A- capital expenditure program, risks with regard to its Senior unsecured debt A3 BBB BBB+ upcoming 2005 rate case and the timing of hurricane cost FPC Capital I recovery as reasons for putting its ratings under review.

Preferred stock* Baa2 BB+ n/a Progress Capital Holdings, Inc. The changes by S&P and Moody's do nottrigger any debt Senior unsecured debt Baal BBB- n/a or guarantee collateral requirements, nor do they have

• Guaranteed by Florida Progress Corporation.

any material impact on the overall liquidity of Progress Energy or any of its affiliates. To date, Progress Energy's, PEC's and PEF's access to the commercial paper markets These ratings reflect the current views of these rating has not been materially impacted by the rating agencies' agencies, and no assurances can be given that these actions. However, the changes have increased the ratings will continue for any given period of time. interest rate incurred on its short-term borrowings by 0.25% to 0.875%.

42

Progress Energy Annual Report 2004 If Standard & Poor's lowers Progress Energy's senior transmission agreements, gas agreements, fuel unsecured rating one ratings category to BB+ from its procurement agreements and trading operations. The current rating, it would be a noninvestment grade rating. Company's guarantees also include standby letters of The effect of a noninvestment grade rating would credit, surety bonds and guarantees in support of nuclear primarily be to increase borrowing costs. The Company's decommissioning. At December31,2004,the Company had liquidity would essentially remain unchanged, as the issued $1.3 billion of guarantees for future financial or Company believes it could borrow under its revolving performance assurance. Management does not believe credit facilities instead of issuing commercial paper conditions are likely for significant performance under the for its short-term borrowing needs. However, there guarantees of performance issued by or on behalf would be additional funding requirements of of affiliates.

approximately $450 million due to ratings triggers embedded in various contracts, as more fully described The majority of contracts supported by the guarantees below under Guarantees.' contain provisions that trigger guarantee obligations based on downgrade events to below investment grade The Company and its subsidiaries' debt indentures and (below BBB- or Baa3), ratings triggers, monthly netting of credit agreements do not contain any ratings triggers," exposure and/or payments and offset provisions in the which would cause the acceleration of interest and event of adefault The recent outlook changes from S&P principal payments in the event of a ratings downgrade. and Moody's do nottrigger any guarantee obligations. As However, in the event of a downgrade, the Company of December 31, 2004, if the guarantee obligations were and/or its subsidiaries may be subject to increased triggered, the maximum amount of liquidity requirements interest costs on the credit facilities backing up the to support ongoing operations within a 90-day period, commercial paper programs. In addition, the Company associated with guarantees for the Company's and its subsidiaries have certain contracts that have nonregulated portfolio and power supply agreements, provisions triggered by a ratings downgrade to a rating was $450 million. The Company would meet this below investment grade. These contracts include obligation with cash or letters of credit counterparty trade agreements, derivative contracts, certain Progress Energy guarantees and various types of As of December 31, 2004, Progress Energy had third-party purchase agreements. guarantees issued on behalf of third parties of approximately $10 million. See Note 23D for adiscussion OFF-BALANCE SHEET ARRANGEMENTS of guarantees inaccordance with FIN No. 45.

AND CONTRACTUAL OBLIGATIONS Market Risk and Derivatives The Company's off-balance sheet arrangements and Under its risk management policy, the Company may use a contractual obligations are described below. variety of instruments, including swaps, options and forward contracts, to manage exposure to fluctuations in Guarantees commodity prices and interest rates. See Note 18 and

'Quantitative and Qualitative Disclosures about Market As a part of normal business, Progress Energy and certain Risk" for a discussion of market risk and derivatives.

wholly owned subsidiaries enter into various agreements providing future financial or performance assurances to Contractual Obligations third parties that are outside the scope of Financial Accounting Standards Board (FASB) Interpretation No. 45, The Company is party to numerous contracts and

'Guarantor's Accounting and Disclosure Requirements for arrangements obligating it to make cash payments in Guarantees, Including Indirect Guarantees of future years. These contracts include financial Indebtedness of Others' (FIN No. 45). These agreements arrangements such as debt agreements and leases, as are entered into primarily to support or enhance the well as contracts for the purchase of goods and services.

creditworthiness otherwise attributed to Progress Energy Amounts in the following table are estimated based upon and subsidiaries on a stand-alone basis, thereby contractual terms and will likely differ from amounts facilitating the extension of sufficient credit to accomplish presented below. Further disclosure regarding the the subsidiaries' intended commercial purposes. The Company's contractual obligations is included in the Company's guarantees include performance obligations respective notes. The Company takes into consideration under power supply agreements, tolling agreements, the future commitments following when assessing its 43

V Management's Discussion and Analysis liquidity and future financing needs. The following table reflects Progress Energy's contractual cash obligations and other commercial commitments at December 31,2004, in the respective periods in which they are due:

(inmillions) Total Less than I year 1-3 years 3-5 years More than 5years Long-term debt al)See Note 13) $9,942 $349 $1,637 S1,387 S6,569 Interest payments on long-term debt and interest rate derivativeslb) 3,064 301 489 423 1,851 Capital lease obligations ISee Note 23C) 50 4 8 7 31 Operating leases (See Note 23C) 597 66 113 112 306 Fuel and purchased power(c)

(See Note 23A) 13,010 2,692 3,088 1,346 5,884 Other purchase obligations (See Note 23A) 633 151 134 80 268 North Carolina Clean Air capital commitments (See Note 22) 764 170 297 143 154 Other commitrnents(d)(e) 243 42 70 26 105 Total S28,303 $3,775 S5,836 $3,524 $15,168 la) The Company's maturing debt obligations are generally expected to be refinanced with new debt issuances inthe capital markets. However, the Company does plan to annually reduce its debt to total capitalization leverage over the next few years through selected asset sales, free cash flow and increased equity from retained earnings and ongoing equity issuances.

lb) Interest payments on long-term debt and interest rate derivatives are based on the interest rate effective as of December 31, 2004, and the LIBOR forward curve as of December 31, 2004, respectively.

IC)Fuel and purchased power commitments represent the majority of the Company's remaining future commitments after its debt obligations. Essentially all of the Company's fuel and purchased power costs are recovered through pass-through clauses inaccordance with North Carolina, South Carolina and Florida regulations and therefore do not require separate liquidity support.

Id)In2008, PEC must begin transitioning amounts currently retained internally to its external decommissioning funds. The transition of S131 million must be complete by December 31,2017, and at least 10% must be transitioned each year.

(e)The Company has certain future commitments related to four synthetic fuel facilities purchased that provide for contingent payments Iroyalties) through 2007 (See Note 23B).

OTHER MATTERS generated inthe future. Similarly, the Financial Accounting Standards Board may issue new accounting rules that Synthetic Fuels Tax Credits would require that uncertain tax benefits (such as those The Company has substantial operations associated with associated with the Earthco plants) be probable of being the production of coal-based synthetic fuels. The sustained in order to be recorded on the financial production and sale of these products qualifies for statements; if adopted, this provision could have an federal income tax credits so long as certain adverse financial impact on the Company.

requirements are satisfied. These operations are subject to numerous risks. The Company's ability to utilize tax credits is dependent on having sufficient tax liability. Any conditions that Although the Company believes that it operates its negatively impact the Company's tax liability, such as synthetic fuel facilities in compliance with applicable legal weather, could also diminish the Company's ability to requirements for claiming the credits, its four Earthco utilize credits, including those previously generated, and facilities are under audit by the IRS. IRS field auditors have the synthetic fuel isgenerally not economical to produce taken an adverse position with respect to the Company's absent the credits. Finally, the tax credits associated with compliance with one of these legal requirements, and if synthetic fuels may be phased out if market prices for the Company fails to prevail with respect to this position, it crude oil exceed certain prices.

could incur significant liability and/or lose the ability to claim the benefit of tax credits carried forward or The Company's synthetic fuel operations and related risks are described in more detail in Note 23E.

44

Progress Energy Annual Report 2004 Hurricane Costs PEF's January 2005 notice to the FPSC of its intent to file for an increase in its base rates effective January 1,2006, Hurricanes Charley, Frances, Ivan and Jeanne struck anticipates the need to replenish the depleted storm significant portions of the Company's service territories reserve balance and adjust the annual S6 million accrual during the third quarter of 2004, significantly impacting in light of recent storm history to restore the reserve to an PEF'sterritory.As of December31, 2004, restoration of the adequate level over a reasonable time period.

Company's systems from hurricane-related damage was estimated at $398 million. PEC incurred restoration costs PEC does not have an ongoing regulatory mechanism to of S13 million, of which S12 million was charged to recover storm costs; therefore, hurricane restoration operation and maintenance expense and S1 million was costs recorded in the third quarter of 2004 were charged charged to capital expenditures. PEF had estimated total to operations and maintenance expenses or capital costs of $385 million, of which $47 million was charged to expenditures based on the nature of the work performed.

capital expenditures, and S338 million was charged to the In connection with other storms, PEC has previously storm damage reserve pursuant to aregulatory order. sought and received permission from the NCUC and the SCPSC to defer storm expenses and amortize them over In accordance with a regulatory order, PEF accrues afive-year period. PEC did not seek deferral of 2004 storm

$6 million annually to a storm damage reserve and is costs from the NCUC (See Note 8B).

allowed to defer losses in excess of the accumulated reserve for major storms. Under the order, the storm Regulatory Environment and Matters reserve is charged with operation and maintenance expenses related to storm restoration and with capital The Company's electric utility operations in North expenditures related to storm restoration that are in Carolina, South Carolina and Florida are regulated by the excess of expenditures assuming normal operating NCUC, the Public Service Commission of South Carolina conditions. As of December 31, 2004, $291 million of (SCPSC) and the FPSC, respectively. The electric hurricane restoration costs in excess of the previously businesses are also subjectto regulation bythe FERC,the recorded storm reserve of S47 million had been classified NRC and otherfederal and state agencies common to the as a regulatory asset recognizing the probable utility business. In addition, the Company is subject to recoverability of these costs. On November 2,2004, PEF SEC regulation as a registered holding company under filed a petition with the FPSC to recover $252 million of PUHCA. As a result of regulation, many of the storm costs plus interest from retail ratepayers over a fundamental business decisions, as well as the rate of two-year period. Storm reserve costs of $13 million were return the electric utilities are permitted to earn, are attributable to wholesale customers. The Company has subject to the approval of governmental agencies.

received approval from the FERC to amortize these costs consistent with recovery of such amounts in wholesale PEC and PEF continue to monitor any developments rates. PEF continues to review the restoration cost toward a more competitive environment and have actively invoices received. Given that not all invoices have been participated in regulatory reform deliberations in North received as of December 31, 2004, PEF will update its Carolina, South Carolina and Florida. Movement toward petition with the FPSC upon receipt and audit of all actual deregulation in these states has been affected by recent charges incurred. Hearings on PEF's petition for recovery developments, including developments related to of S252 million of storm costs filed with the FPSC are deregulation of the electric industry in other states. The scheduled to begin on March 30, 2005. Company expects the legislatures in all three states will continue to monitor the experiences of states that have On November 17, 2004, the Citizens of the State of Florida, implemented electric restructuring legislation. The by and through Harold McLean, Public Counsel, and the Company cannot anticipate when, or if, any of these states Florida Industrial Power Users Group (FIPUG) (collectively, will move to increase competition in the electric industry.

Joint Movants) filed a Motion to Dismiss PEFs petition to recover the $252 million in storm costs. On November 24, The retail rate matters affected by the regulatory 2004, PEF responded inopposition to the motion, which was authorities are discussed in detail in Notes 8B and 8C.

also the FPSC staff's position inits recommendation to the This discussion identifies specific retail rate matters, the Commission on December 21, 2004, that it should deny the status of the issues and the associated effects to the Motion to Dismiss. On January 4,2005, the Commission Company's consolidated financial statements.

ruled infavor of PEF and denied the Joint Movant's Motion to Dismiss. The regulatory authorities continue to evaluate issues related to the formation of Regional Transmission 45

V Management's Discussion and Analysis Organizations. The Company cannot predict the outcome Franchise Litigation of these matters on the Company's earnings, revenues or prices or the investments in GridSouth and GridFlorida Three cities, with a total of approximately 18,000 customers, have litigation pending against PEF in various (See Note 8D).

circuit courts in Florida. As previously reported, three A FERC order issued in November 2001 on certain other cities, with a total of approximately 30,000 unaffiliated utilities' triennial market-based wholesale customers, have subsequently settled their lawsuits with power rate authorization updates required certain PEF and signed new, 30-year franchise agreements. The mitigation actions thatthose utilities would need to take for lawsuits principally seek (1)a declaratory judgment that sales/purchases within their control areas and required the cities have the right to purchase PEF's electric those utilities to post information on their Web sites distribution system located within the municipal regarding their power systems' status. As a result boundaries of the cities, (2)a declaratory judgment that of a request for rehearing filed by certain market the value of the distribution system must be determined participants, FERC issued an order delaying the effective through arbitration, and (3)injunctive relief requiring PEF date of the mitigation plan until after a planned technical to continue to collect from PEF's customers, and remitto conference on market power determination. InDecember the cities, franchise fees during the pending litigation, 2003, the FERC issued a staff paper discussing and as long as PEF continues to occupythe cities' rights-alternatives and held a technical conference in January of-way to provide electric service, notwithstanding the 2004. InApril 2004,the FERC issued two orders concerning expiration of the franchise ordinances under which PEF utilities' ability to sell wholesale electricity at market- had agreed to collect such fees. The circuit courts in based rates. In the first order, the FERC adopted two new those cases have entered orders requiring arbitration to interim screens for assessing potential generation market establish the purchase price of PEF's electric distribution power of applicants for wholesale market-based rates, system within five cities. Two appellate courts have and described additional analyses and mitigation upheld those circuit court decisions and authorized the measures that could be presented if an applicant does not cities to determine the value of PEF's electric distribution pass one of these interim screens. InJuly 2004, the FERC system within the cities through arbitration.

issued an order on rehearing affirming its conclusions in the April order. In the second order, the FERC initiated a Arbitration in one of the cases (with the 13,000-customer rulemaking to consider whether the FERC's current City of Winter Park) was completed in February 2003.

methodology for determining whether a public utility That arbitration panel issued an award in May 2003 should be allowed to sell wholesale electricity at market- setting the value of PEF's distribution system within the based rates should be modified in anyway. Management City of Winter Park (the City) at approximately$32 million, is unable to predict the outcome of these actions by the not including separation and reintegration and FERC or their effect on future results of operations and construction work in progress, which could add several cash flows. PEF does not have market-based rate million dollars to the award. The panel also awarded PEF authority for wholesale sales in peninsular Florida. Given approximately $11 million in stranded costs, which, the difficulty PEC believes it would experience in passing according to the award, decrease over time. In one of the interim screens, on August 12, 2004, PEC September 2003, Winter Park voters passed a notified the FERC that it would revise its Market-based referendum that would authorize the City to issue bonds Rate tariff to restrict it to sales outside PEC's control area of up to approximately $50 million to acquire PEF's and file a new cost-based tariff for sales within PEC's electric distribution system. While the City has not yet control area that incorporates the FERC's default cost- definitively decided whether it will acquire the system, based rate methodologies for sales of one year or less. on April 26, 2004, the City Commission voted to proceed PEC anticipates making this filing in the first quarter of with the acquisition. The City sought and received 2005. Although the Company cannot predict the ultimate wholesale power supply bids and on June 24, 2004, executed a wholesale power supply contract with PEF.

outcome of these changes, the Company does not anticipate that the current operations of PEC or PEF would On May 12, 2004, the City solicited bids to operate and be impacted materially if they were unable to sell power maintain the distribution system and awarded a contract at market-based rates in their respective control areas. in January 2005. The City has indicated that its goal is to begin electric operations in June 2005. On February 10, 2005, PEF filed a petition with the Florida Public Service Commission to relieve the Company of its statutory obligation to serve customers in Winter Park 46

Progress Energy Annual Report 2004 on June 1, 2005, or at such time when the City is able to Legal provide retail service. At this time, whether and when The Company is subject to federal, state and local there will be further proceedings regarding the City of legislation and court orders. These matters are Winter Park cannot be determined.

discussed in detail in Note 23E. This discussion identifies Arbitration with the 2,500-customer Town of Belleair was specific issues, the status of the issues, accruals completed in June 2003. In September 2003, the associated with issue resolutions and the associated arbitration panel issued an award in that case setting the exposures to the Company.

value of the electric distribution system within the Town at approximately $6 million. The panel further required Nuclear the Town to pay to PEF its requested $1 million in Nuclear generating units are regulated bythe NRC. Inthe separation and reintegration costs and $2 million in event of noncompliance, the NRC has the authority to stranded costs. The Town has not yet decided whether it impose fines, set license conditions, shut down a nuclear will attempt to acquire the system; however, on unit or some combination of these, depending upon its January 18, 2005, it issued a request for proposals for assessment of the severity of the situation, until wholesale power supply and to operate and maintain the compliance is achieved. The nuclear units are distribution system. Proposals are due in early periodically removed from service to accommodate March 2005. In February 2005, the Town Commission also normal refueling and maintenance outages, repairs and voted to put the issue of whether to acquire the certain other modifications (See Notes 6 and 23E).

distribution system to a voter referendum on or before October2,2005.Atthistime,whether and when there will Environmental Matters be further proceedings regarding the Town of Belleair The Company is subject to federal, state and local cannot be determined.

regulations addressing air and water quality, hazardous Arbitration in the remaining city's litigation (the 1,500- and solid waste management and other environmental matters. These environmental matters are discussed in customer City of Edgewood) has not yet been scheduled.

detail in Note 22. This discussion identifies specific On February 17, 2005, the parties filed a joint motion to stay the litigation for a 90-day period during which the environmental issues, the status of the issues, accruals parties will discuss potential settlement. associated with issue resolutions and the associated exposures to the Company. The Company accrues costs A fourth city (the 7,000-customer City of Maitland) is to the extent they are probable and can be reasonably contemplating municipalization and has indicated its estimated. It isreasonably possible that additional losses, which could be material, may be incurred in the future.

intent to proceed with arbitration to determine the value of PEF's electric distribution system within the City.

Maitland's franchise expires in August 2005. At this time, New Accounting Standards whether and when there will be further proceedings See Note 2 for a discussion of the impact of new regarding the City of Maitland cannot be determined. accounting standards.

As part of the above litigation, two appellate courts reached opposite conclusions regarding whether PEF must continue to collect from its customers and remit to the cities 'franchise fees' under the expired franchise ordinances. PEFfiled an appeal with the Florida Supreme Court to resolve the conflict between the two appellate courts. On October 28, 2004, the Court issued a decision holding that PEF must collect from its customers and remitto the cities franchise fees during the interim period when the city exercises its purchase option or executes a new franchise. The Court's decision should not have a material impact on the Company.

47

V Market Risk Disclosures QUANTITATIVE AND QUALITATIVE Interest Rate Risk DISCLOSURES ABOUT MARKET RISK The Company manages its interest rate risks through the Market risk represents the potential loss arising from use of a combination of fixed and variable rate debt adverse changes in market rates and prices. Certain Variable rate debt has rates that adjust in periods ranging market risks are inherent in the Company's financial from daily to monthly. Interest rate derivative instruments instruments, which arise from transactions entered into may be used to adjust interest rate exposures and to inthe normal course of business. The Company's primary protect against adverse movements in rates.

exposures are changes in interest rates with respect to its long-term debt and commercial paper, and The following tables provide information at fluctuations in the return on marketable securities with December31, 2004 and 2003, aboutthe Company's interest respect to its nuclear decommissioning trust funds. The rate risk-sensitive instruments. The tables present Company manages its market risk in accordance with its principal cash flows and weighted-average interest rates established risk management policies, which may by expected maturity dates for the fixed and variable rate include entering into various derivative transactions. long-term debt and FPC obligated mandatorily redeemable securities of trust The tables also include These financial instruments are held for purposes other estimates of the fair value of the Company's interest rate than trading. The risks discussed below do not include risk-sensitive instruments based on quoted market prices the price risks associated with nonfinancial instrument for these or similar issues. For interest rate swaps and transactions and positions associated with the interest rate forward contracts, the tables present Company's operations, such as purchase and sales notional amounts and weighted-average interest rates by commitments and inventory. contractual maturity dates for 2005-2009 and thereafter and the fair value of the related hedges. Notional amounts are used to calculate the contractual cash flows to be exchanged under the interest rate swaps and the settlement amounts under the interest rate forward contracts. See Note 18 for more information on interest rate derivatives.

(dollars in millions)

December31. 2004 20(05 2006 2007 2008 2009 Thereafter Total Fair Value Fixed rate long-term debt 73419 $908 $674 $827 $400 $5,399 $8,557 $9,454 Average interest rate 7.38' Y% 6.78% 6.41% 6.27% 5.95% 6.55% 6.54%

Variable rate long-term debt - $55 - - $160 $861 $1,076 $1,077 Average interest rate - 2.95% - - 3.19% 1.70% 1.99%

Debt to affiliated trust(al - - - - - $309 S309 $312 Interest rate _ - - - - 7.10% 7.10%

Interest rate derivatives:

Pay variable/receive fixed - - - 5(100) - 1$50) $(150) $3

_ _ _ (b) _b) (b)

Average pay rate Average receive rate 4.10% - 4.65% 4.28%

Interest rate forward contracts S200 - - $131 $331 $(2)

Average pay rate 3.07% - - 4.90% 3.79%

Average receive rate Ic) - - (b) Ib~c) la) FPC Capital I - Quarterly Income Preferred Securities.

(b)Rate is3-month LIBOR, which was 2.56% at December 31, 2004.

Ic)Rate is1-month LIBOR. which was 2.40% at December 31, 2004.

48

Progress Energy Annual Report 2004 (dollars inmillions)

December3l,2003 2004 2005 2006 2007 2008 Thereafter Total Fair Value Fixed rate long-term debt $868 S349 $909 £674 S827 S5,836 $9,463 $10,501 Averageinterestrate 6.67% 7.38% 6.78% 6.41% 6.27% 6.51% 6.55%

Variable rate long-term debt - - - $241 - S861 S1,102 $1,103 Average interest rate - - - 3.04% - 1.08% 1.51%

Debtto affiliated trustfa1 - - - - - $309 $309 S313 Interest rate - - - - - 7.10% 7.10%

Interest rate derivatives:

Pay variablelreceive fixed - - $(300) $1350) $(200) _ S(850) S(4)

Average pay rate - - (b) (b) (b) _ (b)

Average receive rate - - 2.75% 3.35% 2.93% - 3.04%

Payer swaptions - - - - $400 - $400 $5 Average pay rate - - - - 4.75% -

Average receive rate - - - - (b) -

Interestrate collarslc) $65 - - $130 - _ $195 $(11)

Cap rate 6.00% - - 6.50% -

Floor rate 4.13% - - 5.13%

(a)FPC Capital I - Quarterly Income Preferred Securities.

(b)Rate is 3-month LIBOR, which was 1.15% at December 31.2003.

(c)Notional amount isvarying with amaximum of $195 million, decreasing to S130 million after December 2004.

Marketable Securities Price Risk CVOs are recorded at fair value, and unrealized gains and losses from changes in fair value are recognized in The Company's electric utility subsidiaries maintain trust earnings. At December 31, 2004 and 2003, the fair value of funds, pursuant to NRC requirements, to fund certain these CVOs was S13 million and $23 million, respectively.

costs of decommissioning their nuclear plants. These A hypothetical 10% decrease in the December 31, 2004, funds are primarily invested in stocks, bonds and cash market price would result in a $1 million decrease in the equivalents, which are exposed to price fluctuations in fair value of the CVOs.

equity markets and to changes ininterest rates. The fair value of these funds was $1.044 billion and $938 million at Commodity Price Risk December 31, 2004 and 2003, respectively. The Company actively monitors its portfolio by benchmarking the The Company is exposed to the effects of market performance of its investments against certain indices fluctuations in the price of natural gas, coal, fuel oil, and by maintaining, and periodically reviewing, target electricity and other energy-related products marketed allocation percentages for various asset classes. The and purchased as a result of its ownership of energy-accounting for nuclear decommissioning recognizes related assets. The Company's exposure to these that the Company's regulated electric rates provide fluctuations is significantly limited by the cost-based for recovery of these costs net of any trust fund regulation of PEC and PEF. Each state commission allows earnings, and, therefore, fluctuations in trust fund electric utilities to recover certain of these costs through marketable security returns do not affectthe earnings of various cost recovery clauses to the extent the the Company. respective commission determines that such costs are prudent. Therefore, while there may be a delay in the Contingent Value Obligations timing between when these costs are incurred and when Market Value Risk these costs are recovered from the ratepayers, changes from year to year have no material impact on operating In connection with the acquisition of FPC, the Company results. In addition, many of the Company's long-term issued 98.6 million CVOs. Each CVO represents the right to power sales contracts shift substantially all fuel receive contingent payments based on the performance responsibility to the purchaser. The Company also has oil of four synthetic fuel facilities purchased by subsidiaries price risk exposure related to synfuel tax credits. See of FPC inOctober 1999. The payments, if any, are based on discussion in Note 23E.

the net after-tax cash flows the facilities generate. These 49

V Market Risk Disclosures The Company uses natural gas hedging instruments to manage a portion of the market risk associated with fluctuations in the future sales price of the Company's natural gas. In addition, the Company may engage in limited economic hedging activity using natural gas and electricity financial instruments.

In2004, PEF entered into derivative instruments related to its exposure to price fluctuations on fuel oil purchases. At December 31, 2004, the fair values of these instruments were a $2 million long-term derivative asset position included in other assets and deferred debits and a

$5million short-term derivative liability position included in other current liabilities. These instruments receive regulatory accounting treatment. Gains are recorded in regulatory liabilities and losses are recorded in regulatory assets.

Refer to Note 18 for additional information with regard to the Company's commodity contracts and use of derivative financial instruments.

The Company performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions.

A hypothetical 10% increase or decrease in quoted market prices in the near term on the Company's derivative commodity instruments would not have had a material effect on the Company's consolidated financial position, results of operations or cash flows as of December 31, 2004.

50

V Forward-Looking Statements Progress Energy Annual Report 2004 SAFE HARBOR FOR ability of the Company's subsidiaries to pay upstream FORWARD-LOOKING STATEMENTS dividends or distributions to it; the impact on the facilities and the businesses of the Company from a terrorist Certain matters discussed throughout this Annual Report attack; the inherent risks associated with the operation of that are not historical facts are forward-looking and, nuclear facilities, including environmental, health, accordingly, involve estimates, projections, goals, regulatory and financial risks; the ability to successfully forecasts, assumptions, risks and uncertainties that could access capital markets on favorable terms; the impact on cause actual results or outcomes to differ materially from the Company's financial condition and ability to meet its those expressed in the forward-looking statements. cash and other financial obligations in the event its credit ratings are downgraded below investment grade; the In addition, examples of forward-looking statements impact that increases in leverage may have on the discussed in this Annual Report include Management's Company; the ability of the Company to maintain its Discussion and Analysis of Financial Condition and current credit ratings; the impact of derivative contracts Results of Operations' including, but not limited to, used in the normal course of business by the Company; statements under the following headings: a) "Results of investment performance of pension and benefit plans; the Operations' about trends and uncertainties; b) Liquidity Company's ability to control costs, including pension and and Capital Resources" about operating cash flows, benefit expense, and achieve its cost-management estimated capital requirements through the year 2007 targets for 2007; the availability and use of Internal and future financing plans; c) 'Strategy' about Progress Revenue Code Section 29 (Section 29) tax credits by Energy, Inc.'s, strategy; and d)'Other Matters about the synthetic fuel producers and the Company's continued effects of new environmental regulations, nuclear ability to use Section 29 tax credits related to its coal and decommissioning costs and the effect of electric utility synthetic fuel businesses; the impact to the Company's industry restructuring. financial condition and performance in the event it is determined the Company is not entitled to previously Any forward-looking statement is based on information taken Section 29 tax credits; the impact of future current as of the date of this report and speaks only as of accounting pronouncements regarding uncertain tax the date on which such statement is made and Progress positions; the outcome of PEF's rate proceeding in 2005 Energy, Inc., (the Company) does not undertake any regarding its future base rates; the Company's ability to obligation to update any forward-looking statement or manage the risks involved with the operation of its statements to reflect events or circumstances after the nonregulated plants, including dependence on third date on which such statement is made. parties and related counter-party risks, and a lack of operating history; the Company's ability to manage the Examples of factors thatyou should consider with respect risks associated with its energy marketing operations; the to any forward-looking statements made throughout this outcome of any ongoing or future litigation or similar document include, but are not limited to, the following: the disputes and the impact of any such outcome or related impact of fluid and complex government laws and settlements; and unanticipated changes in operating regulations, including those relating to the environment; expenses and capital expenditures. Many of these risks deregulation or restructuring in the electric industry that similarly impact the Company's subsidiaries.

may result in increased competition and unrecovered (stranded) costs; the ability of the Company to implement These and other risk factors are detailed from time its cost-management initiatives as planned; the to time in the Company's filings with the United uncertainty regarding the timing, creation and structure of States Securities and Exchange Commission (SEC).

regional transmission organizations; weather conditions All such factors are difficult to predict, contain that directly influence the demand for electricity; the uncertainties that may materially affect actual results Company's ability to recover through the regulatory and may be beyond the control of Progress Energy. New process, and the timing of such recovery of, the costs factors emerge from time to time, and it is not possible for associated with the four hurricanes that impacted our managementto predict all such factors, nor can it assess service territory in 2004 or other future significantweather the effect of each such factor on Progress Energy.

events; recurring seasonal fluctuations in demand for electricity, fluctuations inthe price of energy commodities and purchased power; economic fluctuations and the corresponding impact on the Company and its subsidiaries' commercial and industrial customers; the 51

V Independent Auditors' and Management Reports MANAGEMENT'S REPORT OF INTERNAL CONTROLS OVER FINANCIAL REPORTING It is the responsibility of Progress Energy's management to establish and maintain adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15(d)-15(f) of the Securities Exchange Act of 1934, as amended. Progress Energy's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles in the United States of America. Internal control over financial reporting includes policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Progress Energy; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles in the United States of America; (3)provide reasonable assurance that receipts and expenditures of Progress Energy are being made only in accordance with authorizations of management and directors of Progress Energy; and (4) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Progress Energy's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of Progress Energy's internal control over financial reporting as of December 31, 2004. Management based this assessment on criteria for effective internal control over financial reporting described in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Management's assessment included an evaluation of the design of Progress Energy's internal control over financial reporting and testing of the operational effectiveness of its internal control over financial reporting. Management reviewed the results of its assessment with the Audit Committee of the Board of Directors.

Based on our assessment, management determined that, as of December 31, 2004, Progress Energy maintained effective internal control over financial reporting.

Management's assessment of the effectiveness of Progress Energy's internal control over financial reporting as of December 31, 2004, has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report.

Robert B. McGehee Chairman and Chief Executive Officer Geoffrey S. Chatas Executive Vice President and Chief Financial Officer March 7, 2005 52

Progress Energy Annual Report 2004 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Progress Energy, Inc.

We have audited management's assessment, included inthe accompanying Management's Report of Internal Controls, that Progress Energy, Inc., and its subsidiaries (the 'Company') maintained effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control- Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility isto express an opinion on management's assessment and an opinion on the effectiveness of the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management's assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary inthe circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the Company's principal executive and principal financial officers, or persons performing similar functions, and effected by the Company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1)pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (2)provide reasonable assurance thattransactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (3)provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on atimely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management's assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, isfairly stated, inall material respects, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

Also in our opinion, the Company maintained, inall material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2004, of the Company, and our report dated March 7,2005, expressed an unqualified opinion on those consolidated financial statements.

Raleigh, North Carolina March 7,2005 53

V Independent Auditors' and Management Reports REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders of Progress Energy, Inc.

We have audited the accompanying consolidated balance sheets of Progress Energy, Inc., and its subsidiaries (the Company) at December 31, 2004 and 2003, and the related consolidated statements of income, comprehensive income, changes in common stock equity, and cash flows for each of the three years in the period ended December 31, 2004.

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on atest basis, evidence supporting the amounts and disclosures inthe financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Notes ID and 18A to the consolidated financial statements, in 2003, the Company adopted Statement of Financial Accounting Standards No. 143 and Derivatives Implementation Group Issue C20.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company's internal control over financial reporting as of December 31, 2004, based on the criteria established in IntemalControl-IntegratedFrameworkissued bythe Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2005, expressed an unqualified opinion on management's assessment of the effectiveness of the Company's internal control overfinancial reporting and an unqualified opinion on the effectiveness of the Company's internal control over financial reporting.

Raleigh, North Carolina March 7, 2005 54

V Consolidated Financial Statements Progress Energy Annual Report 2004 CONSOLIDATED STATEMENTS OF INCOME (inmillions except per share data)

Years ended December 31 2004 2003 2002 Operating Revenues Electric $7,153 $6,741 $6,601 Diversified business Z619 2,000 1,490 Total Operating Revenues 9,772 8,741 8,091 Operating Expenses Utility Fuel used in electric generation z2011 1,695 1,586 Purchased power 868 862 862 Operation and maintenance 1,475 1,421 1,390 Depreciation and amrortization 878 883 820 Taxes other than on income 425 405 386 Diversified business Cost of sales 2,288 1,748 1,410 Depreciation and amortization 190 157 118 Impairment of long-lived assets - 17 364 (Gain)Aloss on the sale of assets (57) 1 -

Other 218 195 145 Total Operating Expenses 8,296 7,384 7,081 Operating Income 1,476 1,357 1,010 Other Income (Expense)

Interest income 14 11 15 Impairment of investments - (21) (25)

Other, net 8 (16) 27 Total Other Income (Expense) 22 (26) 17 Interest Charges Net interest charges 653 635 641 Allowance for borrowed funds used during construction (6) (7) (8)

Total Interest Charges, Net 647 628 633 Income from Continuing Operations before Income Tax, Minority Interest and Cumulative Effect of Changes in Accounting Principles 851 703 394 Income Tax Expense (Benefit) 115 (111) (158)

Income from Continuing Operations before Minority Interest and Cumulative Effect of Changes in Accounting Principles 736 814 552 Minority Interest Net of Tax (17) 3 -

Income from Continuing Operations Before Cumulative Effect of Changes in Accounting Principles 753 811 552 Discontinued Operations, Net of Tax 6 (8) (24)

Cumulative Effect of Changes in Accounting Principles, Net of Tax - (21)

Net Income $759 $782 $528 Average Common Shares Outstanding 242 237 217 Basic Earnings per Common Share Income from continuing operations before cumulative effect of changes in accounting principles $3.11 $3.42 $2.54 Discontinued operations, net of tax .02 (.03) (.1 1)

Cumulative effect of changes in accounting principles, net of tax - (.09)

Net Income $3.13 $3.30 $2.43 Diluted Earnings per Common Share Income from continuing operations before cumulative effect of changes inaccounting principles S3.10 S3.40 $2.53 Discontinued operations, net of tax .02 (.03) (.11)

Cumulative effect of changes in accounting principles, net of tax - (.09)

Net Income S3.12 $3.28 $2.42 Dividends Declared per Common Share $2.32 $2.26 $2.20 See Notes to Consolidated Financial Statements.

55

V Consolidated Financial Statements CONSOLIDATED BALANCE SHEETS tin millions)

December31 2004 2003 ASSETS Utility Plant Utility plantin service S22.103 $21,680 Accumulated depreciation (8.783) (8,174)

Utility plant in service, net 13,320 13,506 Held for future use 13 13 Construction work inprogress 799 559 Nuclear fuel, net of amortization 231 228 Total Utility Plant, Net 14,363 14,306 Current Assets Cash and cash equivalents 62 47 Short-term investments 82 226 Receivables 1,084 1,084 Inventory 982 907 Deferred fuel cost 229 270 Deferred income taxes 121 87 Prepayments and other current assets 175 268 Total Current Assets 2.735 2,889 Deferred Debits and Other Assets Regulatory assets 1,064 598 Nuclear decommissioning trust funds 1,044 938 Diversified business property, net 2010 2,095 Miscellaneous other property and investments 446 464 Goodwill 3,719 3,726 Prepaid pension costs 42 462 Intangibles, net 337 357 Other assets and deferred debits 233 258 Total Deferred Debits and Other Assets 8,895 8,898 Total Assets $25,993 $26,093 See Notes to Consolidated Financial Statements.

56

Progress Energy Annual Report 2004 CONSOLIDATED BALANCE SHEETS (inmillions)

December31 2004 2003 CAPITAUZATION AND LIABIUTIES Common Stock Equity Common stock Without par value, 500 million shares authorized, 247 million and 246 million shares issued and outstanding, respectively S5,360 S5,270 Unearned restricted shares (1million and 1million shares, respectively) (13) (17)

Unearned ESOP shares (3million and 4 million shares, respectively) 176) (89)

Accumulated other comprehensive loss (164) (50)

Retained earnings 2,526 2,330 Total Common Stock Equity 7,633 7,444 Preferred Stock of Subsidiaries - Not Subject to Mandatory Redemption 93 93 Minority Interest 36 30 Long-Term Debt, Affiliate 270 270 Long-Term Debt, Net 9,251 9,664 Total Capitalization 17,283 17,501 Current Liabilities Current portion of long-term debt 349 868 Accounts payable 742 635 Interest accrued 219 228 Dividends declared 145 140 Short-term obligations 684 4 Customer deposits 180 167 Other current liabilities 742 608 Total Current Liabilities 3,061 2,650 Deferred Credits and Other Liabilities Noncurrent income tax liabilities 599 701 Accumulated deferred investment tax credits 176 190 Regulatory liabilities Z654 2,879 Asset retirement obligations 1,282 1,271 Accrued pension and other benefits 562 508 Other liabilities and deferred credits 376 393 Total Deferred Credits and Other Liabilities 5,649 5,942 Commitments and Contingencies (Notes 22 and 23)

Total Capitalization and Liabilities $25,993 S26,093 See Notes to Consolidated Financial Statements.

57

V Consolidated Financial Statements CONSOLIDATED STATEMENTS OF CASH FLOWS tin millions)

Years ended December 31 2004 2003 2002 Operating Activities Net income S759 $782 $528 Adjustments to reconcile net income to net cash provided by operating activities (Income) loss from discontinued operations (6) 8 24 Net (gain) loss on sale of operating assets (57) 1 -

Impairment of long-lived assets and investments - 38 389 Cumulative effect of changes in accounting principles - 21 -

Depreciation and amortization 1,181 1,146 1,099 Deferred income taxes (74) (276) (402)

Investment tax credit (14) (16) (18)

Deferred fuel credit (19) (133) (37)

Cash provided (used) by changes in operating assets and liabilities Receivables 135) (158) (50)

Inventory (108) 8 (66)

Prepayments and other current assets (18) 39 (24)

Accounts payable 33 37 100 Other current liabilities 82 121 56 Regulatory assets and liabilities (284) (21) 46 Other 167 127 (118)

Net Cash Provided by Operating Activities 1,607 1,724 1,627 Investing Activities Gross utility property additions (998) (972) (1,169)

Diversified business property additions (236) (584) (558)

Nuclear fuel additions (101) (117) (81)

Proceeds from sales of subsidiaries and other investments 366 579 43 Acquisition of businesses, net of cash - - (365)

Purchases of short-term investments (2M108) (2,813) (2,962)

Proceeds from sales of short-term investments 2,252 2,587 2,962 Acquisifion of intangibles (1) (200) (10)

Other (46) (26) (61)

Net Cash Used in Investing Activities (872) (1,546) (2,201)

Financing Activities Issuance of common stock, net 73 304 687 Issuance of long-term debt, net 421 1,539 1,783 Net increase (decrease) in short-term indebtedness 680 (696) (247)

Retirement of long-term debt (1,353) (810) (1,157)

Dividends paid on common stock (558) (541) (480)

Other 17 12 (5)

Net Cash (Used in)Provided by Financing Activities (720) (192) 581 Net Increase (Decrease) in Cash and Cash Equivalents 15 (14) 7 Cash and Cash Equivalents at Beginning of Year 47 61 54 Cash and Cash Equivalents at End of Year $62 $47 $61 Supplemental Disclosures of Cash Flow Information Cash paid during the year - interest (net of amount capitalized) $657 $643 $651

- income taxes (net of refunds) $189 $177 $219 Noncash Activities

• In April 2002, Progress Fuels Corporation, asubsidiary of the Company, acquired 100% of Westchester Gas Company. In conjunction with the purchase, the Company issued approximately S129 million in common stock (See Note 5D).

• In December 2003, Progress Telecommunications Corporation (PTC) and Caronet, Inc., both indirectly wholly owned subsidiaries of Progress Energy, and EPIK Communications, Inc., a wholly owned subsidiary of Odyssey Telecorp, Inc., contributed substantially all of their assets and transferred certain liabilities to Progress Telecom, LLC, a subsidiary of PTC (See Note 5A).

See Notes to Consolidated Financial Statements. 58

Progress Energy Annual Report 2004 CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCK EQUITY Common Common Accumulated Total Stock Stock Unearned Unearned Other Common Outstanding Outstanding Restricted ESOP Comprehensive Retained Stock (inmillionsexceptpersharedata) Shares Amount Shares Shares Income (Loss) Earnings Equity Balance, January 1. 2002 219 S4,121 S(14) $(114) S(32) $2,043 $6,004 Net income 528 528 Other comprehensive loss (206) (206)

Issuance of shares 19 815 815 Purchase of restricted stock (16) (161 Restricted stock expense recognition 8 8 Cancellation of restricted shares (1) 1 Allocation of ESOP shares 16 12 28 Dividends ($2.20 per share) (484) (484)

Balance, December31, 2002 238 4,951 (21) (102) (238) 2,087 6,677 Net income 782 782 Other comprehensive income 188 188 Issuance of shares 8 305 305 Stock options exercised 4 4 Purchase of restricted stock (11 (7) (8)

Restricted stock expense recognition 10 10 Cancellation of restricted shares (11 1 Allocation of ESOP shares 12 13 25 Dividends (S2.26 per share) (539) (539)

Balance, December 31, 2003 246 5,270 (17) (89) (50) 2,330 7,444 Net Income 759 759 Other comprehensive loss (114) 1114)

Issuance of shares 1 62 62 Stock options exercised 16 18 Purchase of restricted stock (7) (7)

Restricted stock expense recognition 7 7 Cancellation of restricted shares (4) 4 Allocation of ESOP shares 14 13 27 Dividends ($2.32 per share) (563) (563)

Balance. December31,2004 247 S5,360 5(13) 5(76) 5(164) 52.526 57,633 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (inmillions)

Years ended December 31 2004 2003 2002 Net Income S759 5782 $528 Other Comprehensive Income (Loss)

Changes in net unrealized losses on cash flow hedges (net of tax benefit of $10, S7 and $18, respectively) (18) 112) (28)

Reclassification adjustmentfor amounts included innet income (net of tax expense of (S16),1(il and ($10), respectively) 26 19 16 Reclassification of minimum pension liability to regulatory assets (net of tax expense of ($2)) 4 - -

Minimum pension liability adjustment (net of tax benefit (expense) of $78, ($112) and $121, respectively) (130) 177 (192)

Foreign currency translation and other 4 4 (2)

Other Comprehensive Income (Loss) $(114) 5188 51206)

Comprehensive Income 5645 5970 $322 See Notes to Consolidated Financial Statements.

59

V Notes to Consolidated Financial Statements

1. ORGANIZATION AND

SUMMARY

that profits on intercompany sales to regulated affiliates OF SIGNIFICANT ACCOUNTING POLICIES are not eliminated if the sales price is reasonable and the future recovery of the sales price through the ratemaking A. Organization process is probable.

Progress Energy, Inc. (Progress Energy or the Company) is a holding company headquartered in Raleigh, North The consolidated financial statements of the Company Carolina. The Company is registered under the Public and its subsidiaries include the majority-owned and Utility Holding Company Act of 1935 (PUHCA), as controlled subsidiaries. Noncontrolling interests in the amended, and as such, the Company and rts subsidiaries subsidiaries along with the income or loss attributed to are subject to the regulatory provisions of PUHCA. these interests are included in minority interest in both Effective January 1, 2003, three of the Company's the Consolidated Balance Sheets and in the subsidiaries, Carolina Power & Light Company (CP&L), Consolidated Statements of Income. The results of Florida Power Corporation and Progress Ventures, Inc., operations for minority interest are reported on a net of began doing business under the assumed names tax basis if the underlying subsidiary is structured as a Progress Energy Carolinas, Inc. (PEC), Progress Energy taxable entity.

Florida, Inc. (PEF) and Progress Energy Ventures, Inc.

(PVI), respectively. Unconsolidated investments in companies over which the Company does not have control, but has the ability to Through its wholly owned subsidiaries, PEC and PEF, the exercise influence over operating and financial policies Company's PEC Electric and PEF segments are primarily (generally 20%-50% ownership), are accounted for engaged in the generation, transmission, distribution and under the equity method of accounting. These sale of electricity in portions of North Carolina, South investments are primarily in limited liability corporations Carolina and Florida. The Progress Ventures business unit and limited liability partnerships, and the earnings from consists of the Fuels business segment (Fuels) and these investments are recorded on a pre-tax basis (See Competitive Commercial Operations (CCO) operating Note 21). These equity method investments are included segments. The Fuels segment is involved in natural gas in miscellaneous other property and investments in the drilling and production, coal terminal services, coal mining, Consolidated Balance Sheets. At December 31, 2004 and synthetic fuel production, fuel transportation and delivery. 2003, the Company has equity method investments of The CCO segment includes nonregulated generation and approximately $27 million and $36 million, respectively.

energy marketing activities. Through the Rail Services (Rail) segment, the Company is involved in nonregulated Certain investments in debt and equity securities that railcar repair, rail parts reconditioning and sales and scrap have readily determinable market values, and for which metal recycling. Through its other business units, the the Company does not have control, are accounted for as Company engages in other nonregulated business areas, available-for-sale securities at fair value in accordance including telecommunications and energy management with SFAS No. 115, 'Accounting for Certain Investments and related services. Progress Energy's legal structure is in Debt and Equity Securities.' These investments not currently aligned with the functional management and include investments held in trust funds, pursuant to the financial reporting of the Progress Ventures business unit. United States Nuclear Regulatory Commission (NRC)

Whether, and when, the legal and functional structures will requirements, to fund certain costs of decommissioning converge depends upon legislative and regulatory action, nuclear plants. The fair value of these trust funds was which cannot currently be anticipated. $1.044 billion and S938 million at December 31, 2004 and 2003, respectively. The Company also actively invests B. Basis of Presentation available cash balances in various financial instruments, such as tax-exempt debt securities that have stated The consolidated financial statements are prepared in maturities of 20 years or more. These instruments provide accordance with accounting principles generally for a high degree of liquidity through arrangements with accepted in the United States of America (GAAP) and banks that provide daily and weekly liquidity and 7,28 and include the activities of the Company and its majority- 35 day auctions that allow for the redemption of the owned subsidiaries. Significant intercompany balances investment at its face amount plus earned income. As the and transactions have been eliminated in consolidation Company intends to sell these instruments generally except as permitted by Statement of Financial within 30 days from the balance sheet date, they are Accounting Standards (SFAS) No.71, Accounting forthe classified as current assets. At December 31, 2004 and Effects of Certain Types of Regulation," which provides 2003, the fair value of these investments was $82 million 60

Progress Energy Annual Report 2004 and $226 million, respectively. Other investments in debt partnerships that qualify for federal and state tax credits.

and equity securities are included in miscellaneous The Company has requested but has not received all the other property and investments in the Consolidated necessary information to determine the primary Balance Sheets. At December 31, 2004 and 2003, the fair beneficiary of the limited partnership's underlying 17 value of these other investments was S39 million and partnership investments, and has applied the information

$39 million, respectively. scope exception in FIN No. 46R, paragraph 4(g) to the 17 partnerships. The Company has no direct exposure to loss Other investments are stated principally at cost These cost from the 17 partnerships; the Company's only exposure to method investments are included in miscellaneous other loss is from its investment of less than $1 million in the property and investments in the Consolidated Balance consolidated limited partnership. The Company will Sheets. At December 31, 2004, and 2003, the Company has continue its efforts to obtain the necessary information to approximately $14 million and $14 million, respectively, of fully apply FIN No.46R to the 17 partnerships. The Company cost method investments. believes that if the limited partnership is determined to be the primary beneficiary of the 17 partnerships, the effect of The results of operations of Rail are reported one month in consolidating the 17 partnerships would not be significant arrears. During 2003, the Company ceased recording to the Company's Consolidated Balance Sheets.

portions of the Fuels' segment operations one month in arrears. The net impact of this action increased net income The Company has variable interests in two power plants by$2 million for the year. resulting from long-term power purchase contracts. The Company has requested the necessary information to Certain amounts for 2003 and 2002 have been determine if the counterparties are variable interest reclassified to conform to the 2004 presentation. entities or to identify the primary beneficiaries. Both Reclassifications include the reclassification of entities declined to provide the Company with the instruments used in PEC's cash management program necessary financial information, and the Company has from cash and cash equivalents to short-term applied the information scope exception in FIN No. 46R, investments of $226 million at December 31, 2003, in the paragraph 4(g). The Company's only significant exposure Consolidated Balance Sheets. In the Consolidated to variability from these contracts results from Statements of Cash Flow for each of the three years in fluctuations in the market price of fuel used by the two the period ended December 31, 2004, total cash entities' plants to produce the power purchased by the balances and total cash flows used in investing activities Company. The Company is able to recover these fuel were revised to reflect the reclassification of these costs under PEC's fuel clause. Total purchases from these instruments from cash and cash equivalents to short- counterparties were approximately $58 million, $53 million term investments. and $53 million in 2004, 2003 and 2002, respectively. The Company will continue its efforts to obtain the necessary C. Consolidation of Variable Interest Entities information to fully apply FIN No. 46R to these contracts.

The combined generation capacity of the two entities' The Company consolidates all voting interest entities in power plants is approximately 880 MW. The Company which it owns a majority voting interest and all variable believes that if it is determined to be the primary interest entities for which it is the primary beneficiary in beneficiary of these two entities, the effect of accordance with FASB Interpretation No. 46R, consolidating the entities would result in increases to "Consolidation of Variable Interest Entities -An Interpretation total assets, long-term debt and other liabilities, butwould of ARB No. 51" (FIN No. 46R). The Company is the primary have an insignificant or no impact on the Company's beneficiary of and consolidates two limited partnerships common stock equity, net earnings or cash flows.

that qualify for federal affordable housing and historic tax However, because the Company has not received any credits under Section 42 of the Internal Revenue Code financial information from these two counterparties, the (Code). As of December 31,2004, the total assets of the two impact cannot be determined at this time.

entities were $37 million, the majority of which are collateral for the entities' obligations and are included in The Company also has interests in several other variable other current assets and miscellaneous other property and interest entities for which the Company is not the investments in the Consolidated Balance Sheets.

primary beneficiary. These arrangements include investments in approximately 28 limited partnerships, The Company is the primary beneficiary of a limited limited liability corporations and venture capital funds partnership that invests in 17 low-income housing and two building leases with special-purpose entities.

61

V Notes to Consolidated Financial Statements The aggregate maximum loss exposure at December31,2004, excise taxes of approximately S240 million, $217 million that the Company could be required to record in its and $212 million, respectively, are included in utility income statement as a result of these arrangements revenues and taxes other than on income in the totals approximately $38 million. The creditors of these Consolidated Statements of Income.

variable interest entities do not have recourse to the general credit of the Company in excess of the STOCK-BASED COMPENSATION aggregate maximum loss exposure.

The Company measures compensation expense for stock D. Significant Accounting Policies options as the difference between the market price of its common stock and the exercise price of the option at the USE OF ESTIMATES AND ASSUMPTIONS grant date. The exercise price at which options are In preparing consolidated financial statements that granted by the Company equals the market price at the conform with GAAP, management must make estimates grant date, and accordingly, no compensation expense and assumptions that affect the reported amounts of has been recognized for stock option grants. For assets and liabilities, disclosure of contingent assets and purposes of the pro forma disclosures required by SFAS liabilities at the date of the consolidated financial No. 148, Accounting for Stock-Based Compensation -

statements and amounts of revenues and expenses Transition and Disclosure - An Amendment of FASB reflected during the reporting period. Actual results Statement No. 123" ISFAS No. 148), the estimated fair could differ from those estimates. value of the Company's stock options is amortized to expense over the options' vesting period. The following REVENUE RECOGNITION table illustrates the effect on net income and earnings per share if the fair value method had been applied to all The Company recognizes electric utility revenues as outstanding and unvested awards in each period:

service is rendered to customers. Operating revenues include unbilled electric utility revenues earned when (inmillions except per share data) 2004 2003 2002 service has been delivered but not billed by the end of Net income, as reported $759 $782 $528 the accounting period. Diversified business revenues Deduct Total stock option expense are generally recognized at the time products are determined under fair value method for shipped or as services are rendered. Leasing activities all awards, net of related tax effects 10 11 8 are accounted for in accordance with SFAS No. 13, Pro forma net income $749 $771 S520 Accounting for Leases.' Revenues related to design Earnings per share and construction of wireless infrastructure are Basic - as reported $3.13 $3.30 $2.43 recognized upon completion of services for each Basic - pro forma $3.09 $3.25 S2.40 completed phase of design and construction. Revenues Diluted - as reported $3.12 $3.28 $2.42 from the sale of oil and gas production are recognized Diluted - pro forma $3.08 $3.24 $2.39 when title passes, net of royalties.

See Note 2 for a discussion of newly issued accounting FUEL COST DEFERRALS guidance related to stock-based compensation.

Fuel expense includes fuel costs or recoveries that are deferred through fuel clauses established by the electric UTILITY PLANT utilities' regulators. These clauses allow the utilities to Utility plant in service is stated at historical cost less recover fuel costs and portions of purchased power accumulated depreciation. The Company capitalizes all costs through surcharges on customer rates. These construction-related direct labor and material costs of deferred fuel costs are recognized in revenues and fuel units of property as well as indirect construction costs.

expenses as they are billable to customers. Certain costs that would otherwise not be capitalized under GAAP are capitalized in accordance with EXCISE TAXES regulatory treatment. The cost of renewals and PEC and PEF collect from customers certain excise taxes betterments is also capitalized. Maintenance and repairs levied by the state or local government upon the of property (including planned major maintenance customers. PEC and PEF account for excise taxes on a activities), and replacements and renewals of items gross basis. For the years ended December 31,2004,2003 determined to be less than units of property, are charged and 2002, gross receipts tax, franchise taxes and other to maintenance expense as incurred, with the exception of nuclear outages at PEF. Pursuant to a regulatory order, 62

Progress Energy Annual Report 2004 PEF accrues for nuclear outage costs in advance of jurisdictions, provisions for nuclear decommissioning scheduled outages, which occur every two years. The costs are approved bythe NCUC,the SCPSC and the FPSC cost of units of property replaced or retired, less salvage, and are based on site-specific estimates that include the is charged to accumulated depreciation. Removal or costs for removal of all radioactive and other structures at disposal costs that do not represent SFAS No. 143, the site. In the wholesale jurisdictions, the provisions for

'Accounting for Asset Retirement Obligations' (SFAS No. nuclear decommissioning costs are approved by the 143), are charged to a regulatory liability. Federal Energy Regulatory Commission (FERC).

Allowance for funds used during construction (AFUDC) CASH AND CASH EQUIVALENTS represents the estimated debt and equity costs of capital funds necessary to finance the construction of new The Company considers cash and cash equivalents to regulated assets. As prescribed in the regulatory uniform include unrestricted cash on hand, cash in banks and system of accounts, AFUDC is charged to the cost of the temporary investments purchased with a maturity of plant. The equity funds portion of AFUDC is credited to three months or less.

other income and the borrowed funds portion is credited to interest charges. INVENTORY The Company accounts for inventory using the average-ASSET RETIREMENT OBLIGATIONS cost method. Inventories are valued at the lower of Effective January 1, 2003, the Company adopted the average cost or market.

guidance in SFAS No. 143 to account for legal obligations associated with the retirement of certain tangible long- REGULATORY ASSETS AND LIABILITIES lived assets. The present value of retirement costs for The Company's regulated operations are subject to SFAS which the Company has a legal obligation are recorded No. 71, which allows a regulated companyto record costs as liabilities with an equivalent amount added to the that have been or are expected to be allowed in the asset cost and depreciated over an appropriate period. ratemaking process in a period differentfrom the period in The liability is then accreted over time by applying an which the costs would be charged to expense by a interest method of allocation to the liability. nonregulated enterprise. Accordingly, the Company records assets and liabilities that result from the The adoption of this statement had no impact on the regulated ratemaking processthatwould not be recorded income of the regulated entities, as the effects were under GAAP for nonregulated entities. These regulatory offset by the establishment of a regulatory asset and a assets and liabilities represent expenses deferred for regulatory liability pursuant to SFAS No.71 (See Note 8A). future recovery from customers or obligations to be The North Carolina Utilities Commission (NCUC), the refunded to customers and are primarily classified in the Public Service Commission of South Carolina (SCPSC) Consolidated Balance Sheets as regulatory assets and and the Florida Public Service Commission (FPSC) issued regulatory liabilities (See Note 8A).

orders to authorize deferral of all prospective effects related to SFAS No. 143 as a regulatory asset or liability DIVERSIFIED BUSINESS PROPERTY (See Note 8A). Therefore, SFAS No. 143 has no impact on the income of the regulated entities. Diversified business property is stated at cost less accumulated depreciation. If an impairment is recognized DEPRECIATION AND AMORTIZATION - UTILITY PLANT on an asset, the fair value becomes its new cost basis.

The costs of renewals and betterments are capitalized.

For financial reporting purposes, substantially all The cost of repairs and maintenance is charged to depreciation of utility plant other than nuclear fuel is expense as incurred. For properties other than oil and gas computed on the straight-line method based on the properties, depreciation is computed on a straight-line estimated remaining useful life of the property, adjusted basis using the estimated useful lives disclosed in Note for estimated salvage (See Note 6A). Pursuant to their 6B. Depletion of mineral rights is provided on the units-of-rate-setting authority, the NCUC, SCPSC and FPSC can production method based upon the estimates of also grant approval to accelerate or reduce depreciation recoverable amounts of clean mineral.

and amortization of utility assets (See Note 8).

The Company uses the full-cost method to account for its Amortization of nuclear fuel costs is computed primarily oil and gas properties. Under the full-cost method, on the units-of-production method. Inthe Company's retail substantially all productive and nonproductive costs 63

V Notes to Consolidated Financial Statements incurred in connection with the acquisition, exploration related properties. Credits for the production and sale of and development of oil and gas reserves are capitalized. synthetic fuel are deferred as AMT credits to the extent These capitalized costs include the costs of all unproved they cannot be or have not been utilized in the annual properties and internal costs directly related to consolidated federal income tax returns, and are acquisition and exploration activities. The amortization included in income tax expense (benefit) in the base also includes the estimated future cost to develop Consolidated Statements of Income.

proved reserves. Except for costs of unproved properties and major development projects in progress, all costs are DERIVATIVES amortized using the units-of-production method on a The Company accounts for derivative instruments in country by country basis over the life of the Company's accordance with SFAS No. 133, 'Accounting for proved reserves. Accordingly, all property acquisition, Derivative Instruments and Hedging Activities' (SFAS exploration, and development costs of proved oil and gas No. 133), as amended by SFAS No. 138 and SFAS No. 149.

properties, including the costs of abandoned properties, SFAS No. 133, as amended, establishes accounting and dry holes, geophysical costs and annual lease rentals are reporting standards for derivative instruments, including capitalized as incurred, including internal costs directly certain derivative instruments embedded in other attributable to such activities. Related interest expense contracts, and for hedging activities. SFAS No. 133 incurred during property development activities is requires that an entity recognize all derivatives as assets capitalized as a cost of such activity. Net capitalized or liabilities in the balance sheet and measure those costs of unproved property are reclassified as proved instruments at fair value, unless the derivatives meet the property and well costs when related proved reserves SFAS No. 133 criteria for normal purchases or normal are found. Costs to operate and maintain wells and field sales and are designated as such. The Company equipment are expensed as incurred. Inaccordance with generally designates derivative instruments as normal Rule 4-10 of Regulation S-X, sales or other dispositions of purchases or normal sales whenever the SFAS No. 133 oil and gas properties are accounted for as adjustments criteria are met. If normal purchase or normal sale to capitalized costs, with no gain or loss recorded unless criteria are not met, the Company will generally certain significance tests are met. designate the derivative instruments as cash flow or fair value hedges if the related SFAS No. 133 hedge criteria GOODWILL AND INTANGIBLE ASSETS are met. During 2003, the FASB reconsidered an Goodwill is subject to at least an annual assessment for interpretation of SFAS No. 133. See Note 18 for the effect impairment by applying a two-step fair-value-based test. of the interpretation and additional information regarding This assessment could result in periodic impairment risk management activities and derivative transactions.

charges. Intangible assets are being amortized based on the economic benefit of their respective lives. ENVIRONMENTAL As discussed in Note 22, the Company accrues UNAMORTIZED DEBT PREMIUMS, DISCOUNTS environmental remediation liabilities when the criteria for AND EXPENSES SFAS No. 5, 'Accounting for Contingencies" (SFAS No.

Long-term debt premiums, discounts and issuance 5), have been met. Environmental expenditures that expenses are amortized over the terms of the debt relate to an existing condition caused by past operations issues. Any expenses or call premiums associated with and that have no future economic benefits are expensed.

the reacquisition of debt obligations by the utilities are Accruals for estimated losses from environmental amortized over the applicable life using the straight-line remediation obligations generally are recognized no later method consistent with ratemaking treatment (See than completion of the remedial feasibility study. Such Note 8A). accruals are adjusted as additional information develops or circumstances change. Costs of future expenditures INCOME TAXES for environmental remediation obligations are not The Company and its affiliates file a consolidated federal discounted to their present value. Recoveries of income tax return. Deferred income taxes have been environmental remediation costs from other parties are provided for temporary differences. These occur when recognized when their receipt is deemed probable.

there are differences between the book and tax carrying Environmental expenditures that have future economic amounts of assets and liabilities. Investment tax credits benefits are capitalized in accordance with the related to regulated operations have been deferred and Company's asset capitalization policy.

are being amortized over the estimated service life of the 64

Progress Energy Annual Report 2004 IMPAIRMENT OF LONG-LIVED ASSETS 2. NEW ACCOUNTING STANDARDS AND INVESTMENTS FASB STAFF POSITION 106-2, 'ACCOUNTING AND As discussed in Note 10, the Company reviews the DISCLOSURE REQUIREMENTS RELATED TO THE recoverability of long-lived tangible and intangible assets MEDICARE PRESCRIPTION DRUG IMPROVEMENT AND whenever indicators exist Examples of these indicators MODERNIZATION ACT OF 2003" include current period losses, combined with a history of In December 2003, the Medicare Prescription Drug losses or a projection of continuing losses, or asignificant Improvement and Modernization Act of 2003 (Medicare decrease in the market price of a long-lived asset group. Act) was signed into law. In accordance with guidance If an indicator exists for assets to be held and used, then issued by the Financial Accounting Standards Board the asset group is tested for recoverability by comparing (FASB) in FASB Staff Position 106-1, 'Accounting and the carrying value to the sum of undiscounted expected Disclosure Requirements Related to the Medicare future cash flows directly attributable to the asset group. Prescription Drug Improvement and Modernization Act of If the asset group is not recoverable through 2003" (FASB Staff Position 106-1), the Company elected to undiscounted cash flows or the asset group is to be defer accounting for the effects of the Medicare Act due disposed of, then an impairment loss is recognized for the to uncertainties regarding the effects of the difference between the carrying value and the fair value implementation of the Medicare Act and the accounting of the asset group. The accounting for impairment of for certain provisions of the Medicare Act In May 2004, assets is based on SFAS No. 144, 'Accounting for the the FASB issued definitive accounting guidance for the Impairment or Disposal of Long-Lived Assets." Medicare Act in FASB Staff Position 106-2, which was effective for the Company in the third quarter of 2004.

The Company reviews its investments to evaluate whether FASB Staff Position 106-2 results in the recognition of or not a decline in fair value below the carrying value is an lower other postretirement employment benefit (OPEB) other-than-temporary decline. The Company considers costs to reflect prescription drug-related federal various factors, such as the investee's cash position, subsidies to be received under the Medicare Act As a earnings and revenue outlook, liquidity and management's result of the Medicare Act, the Company's accumulated ability to raise capital in determining whether the decline postretirement benefit obligation as of January 1, 2004, is other-than-temporary. If the Company determines that was reduced by approximately $83 million, and the an other-than-temporary decline exists in the value of its Company's 2004 net periodic cost was reduced by investments, it is the Company's policy to write-down approximately $13 million.

these investments to fair value.

SFAS NO. 123 (REVISED 2004), SHARE-BASED Under the full-cost method of accounting for oil and gas PAYMENT' (SFAS NO. 123R) properties, total capitalized costs are limited to a ceiling based on the present value of discounted (at 10%) future In December 2004, the FASB issued SFAS No. 123R, net revenues using current prices, plus the lower of cost which revises SFAS No. 123, 'Accounting for Stock-or fair market value of unproved properties. The ceiling Based Compensation," and supersedes Accounting test takes into consideration the prices of qualifying cash Principles Board {APB) Opinion No. 25, "Accounting for flow hedges as of the balance sheet date. If the ceiling Stock Issued to Employees." The key requirement of (discounted revenues) isnot equal to or greaterthan total SFAS No. 123R isthat the cost of share-based awards to capitalized costs, the Company is required to write-down employees will be measured based on an award's fair capitalized costs to this level. The Company performs this value at the grant date, with such cost to be amortized ceiling test calculation every quarter. No write-downs over the appropriate service period. Previously, entities were required in 2004, 2003 or 2002. could elect to continue accounting for such awards at their grant date intrinsic value under APB Opinion No. 25, SUBSIDIARY STOCK TRANSACTIONS and the Company made that election. The intrinsic value method resulted in the Company recording no Gains and losses realized as a result of common stock compensation expense for stock options granted to sales by the Company's subsidiaries are recorded in the employees (See Note 11).

Consolidated Statements of Income, except for any transactions that must be credited directly to equity in SFAS No. 123R will be effective for the Company on accordance with the provisions of Staff Accounting July 1, 2005. The Company intends to implement the Bulletin No. 51, 'Accounting for Sales of Stock by standard using the required modified prospective a Subsidiary." method. Under that method, the Company will record 65

V Notes to Consolidated Financial Statements compensation expense under SFAS No. 123R for all expenditures related to storm restoration that are in awards it grants after July 1, 2005, and it will record excess of expenditures assuming normal operating compensation expense (as previous awards continue to conditions. As of December 31, 2004, $291 million of vest) for the unvested portion of previously granted hurricane restoration costs in excess of the previously awards that remain outstanding at July 1,2005. In 2004, recorded storm reserve of $47 million had been classified the Company made the decision to cease granting stock as a regulatory asset recognizing the probable options and intends to replace that compensation recoverability of these costs. On November 2, 2004, PEF program with other programs. Therefore, the amount of filed a petition with the FPSC to recover $252 million of stock option expense expected to be recorded in 2005 is storm costs plus interest from retail ratepayers over a below the amount that would have been recorded if the two-year period. Storm reserve costs of $13 million were stock option program had continued. The Company attributable to wholesale customers. The Company has expects to record approximately $3 million of pre-tax received approval from the FERC to amortize these costs expense for stock options in 2005. consistent with recovery of such amounts in wholesale rates. PEF continues to review the restoration cost PROPOSED FASB INTERPRETATION OF SFAS NO. 109, invoices received. Given that not all invoices have been "ACCOUNTING FOR INCOME TAXES" received as of December 31, 2004, PEF will update its In July 2004, the FASB stated that it plans to issue an petition with the FPSC upon receipt and audit of all actual exposure draft of a proposed interpretation of SFAS No. charges incurred. Hearings on PEF's petition for recovery 109, Accounting for Income Taxes" (SFAS No. 109), that of $252 million of storm costs filed with the FPSC are would address the accounting for uncertain tax scheduled to begin on March 30, 2005.

positions. The FASB has indicated that the interpretation would require that uncertain tax benefits be probable of On November 17, 2004, the Citizens of the State of Florida, being sustained in order to record such benefits in the by and through Harold McLean, Public Counsel, and the consolidated financial statements. The exposure draft is Florida Industrial Power Users Group (FIPUG),

expected to be issued in the first quarter of 2005. The (collectively, Joint Movants), filed a Motion to Dismiss Company cannot predict what actions the FASB will take PEF's petition to recover the $252 million in storm costs.

or how any such actions might ultimately affect the On November 24, 2004, PEF responded in opposition to Company's financial position or results of operations, but the motion, which was also the FPSC staff's position in its such changes could have a material impact on the recommendation to the Commission on December 21, Company's evaluation and recognition of Section 29 tax 2004, that it should deny the Motion to Dismiss. On credits (See Note 23E). January 4,2005, the Commission ruled in favor of PEF and denied Joint Movant's Motion to Dismiss.

3. HURRICANE-RELATED COSTS PEF's January 2005 notice to the FPSC of its intent to file Hurricanes Charley, Frances, Ivan and Jeanne struck for an increase in its base rates effective January 1,2006, significant portions of the Company's service territories anticipates the need to replenish the depleted storm during the third quarter of 2004, significantly impacting reserve balance and adjustthe annual $6million accrual PEF's territory. As of December 31, 2004, restoration of the in light of recent storm history to restore the reserve to Company's systems from hurricane-related damage was an adequate level over a reasonable time period (See estimated at S398 million. PEC incurred restoration costs Note 8C).

of $13 million, of which $12 million was charged to operation and maintenance expense and $1 million was PEC does not have an ongoing regulatory mechanism to charged to capital expenditures. PEF had estimated total recover storm costs; therefore, hurricane restoration costs of $385 million, of which $47 million was charged to costs recorded inthe third quarter of 2004 were charged capital expenditures, and S338 million was charged to the to operations and maintenance expenses or capital storm damage reserve pursuant to a regulatory order. expenditures based on the nature of the work performed.

In connection with other storms, PEC has previously In accordance with a regulatory order, PEF accrues sought and received permission from the NCUC and the

$6 million annually to a storm damage reserve and is SCPSC to defer storm expenses and amortize them over allowed to defer losses in excess of the accumulated a five-year period. PEC did not seek deferral of 2004 storm reserve for major storms. Under the order, the storm costs from the NCUC (See Note 8B).

reserve is charged with operation and maintenance expenses related to storm restoration and with capital 66

Progress Energy Annual Report 2004

4. DIVESTITURES letter of intent to sell the majority of Railcar Ltd. assets to The Andersons, Inc., and the transaction closed in A. Sale of Natural Gas Assets February 2004. Proceeds from the sale were In December 2004, the Company sold certain gas- approximately $82 million before transaction costs and producing properties and related assets owned by taxes of approximately $13 million. In July 2004, the Winchester Production Company, Ltd. (Winchester Company sold the remaining assets classified as held for Production), an indirectly wholly owned subsidiary of sale to a third-party for net proceeds of $6 million. The Progress Fuels Corporation (Progress Fuels), which is assets of Railcar Ltd. were grouped as assets held for included in the Fuels segment. Net proceeds of sale and were included in other current assets on the approximately S251 million were used to reduce debt Consolidated Balance Sheets at December 31, 2003, at Because the sale significantly altered the ongoing approximately $75 million, which reflected the Company's relationship between capitalized costs and remaining estimates of the fair value expected to be realized from proved reserves, under the full-cost method of the sale of these assets less costs to sell.

accounting, the pre-tax gain of $56 million was recognized in earnings rather than as a reduction of the D. Mesa Hydrocarbons, Inc., Divestiture basis of the Company's remaining oil and gas properties. InOctober 2003, the Company sold certain gas-producing The pre-tax gain has been included in (gain)Iloss on the properties owned by Mesa Hydrocarbons, LLC, a wholly sale of assets inthe Consolidated Statements of Income. owned subsidiary of Progress Fuels. Net proceeds were approximately $97 million. Because the Company utilizes B. Divestiture of Synthetic Fuel the full-cost method of accounting for its oil and gas Partnership Interests operations, the pre-tax gain of approximately $18 million InJune 2004, the Company through its subsidiary, Progress was applied to reduce the basis of the Company's other Fuels, sold, in two transactions, a combined 49.8% U.S. oil and gas investments and will prospectively result partnership interest in Colona Synfuel Limited Partnership, in a reduction of the amortization rate applied to those LLLP, one of its synthetic fuel facilities. Substantially all investments as production occurs.

proceeds from the sales will be received over time, which istypical of such sales inthe industry. Gain from the sales E. NCNG Divestiture will be recognized on acost recovery basis. The Company's On September 30, 2003, the Company completed the sale book value of the interests sold totaled approximately of North Carolina Natural Gas Corporation (NCNG) and the

$5 million. The Company received total gross proceeds of Company's equity investment in Eastern North Carolina

$10 million in2004. Based on projected production and tax Natural Gas Company (ENCNG) to Piedmont Natural Gas credit levels, the Company anticipates receiving Company, Inc. Net proceeds from the sale of NCNG of approximately S24 million in2005, approximately $31 million approximately $443 million were used to reduce debt.

in2006, approximately$32 million in2007, and approximately S8 million through the second quarter of 2008. Inthe event The consolidated financial statements have been that the synthetic fuel tax credits from the Colona facility restated for all periods presented for the discontinued are reduced, including an increase in the price of oil that operations of NCNG. The net income of these operations could limit or eliminate synthetic fuel tax credits, the is reported as discontinued operations in the amount of proceeds realized from the sale could be Consolidated Statements of Income. Interest expense of significantly impacted. $10 million and $16 million for the years ended December 31, 2003 and 2002, respectively, has been C. Railcar Ltd., Divestiture allocated to discontinued operations based on the net In December 2002, the Progress Energy Board of assets of NCNG, assuming a uniform debt-to-equity ratio Directors adopted a resolution approving the sale of across the Company's operations. The Company ceased Railcar Ltd., a subsidiary included in the Rail Services recording depreciation effective October 1, 2002, upon segment. An estimated pre-tax impairment of $59 million classification of the assets as discontinued operations.

on assets held for sale was recognized in December 2002 After-tax depreciation expense recorded by NCNG for to write-down the assets to fair value less costs to sell. the year ended December 31, 2002, was $9 million.

This impairment has been included inimpairment of long- Results of discontinued operations for years ended lived assets in the Consolidated Statements of Income December 31 were as follows:

(See Note 10A). In March 2003, the Company signed a 67

V Notes to Consolidated Financial Statements (inmillionsJ 2004 2003 2002 valuation of acquired assets and liabilities. Management Revenues $284 $3D0 considered a number of factors, including valuations and Earnings before income taxes $6 $9 appraisals, when making these determinations. Based on the results of these activities, the preliminary purchase Income tax expense 2 4

.

price allocation for EPIK was revised as follows at Net earnings from discontinued operations 4 5 December 31, 2004: property and equipment-S36 million; Gain/l(Loss) on disposal of discontinued other current assets - $7 million; intangible assets -

operations, including applicable income tax benefit/lexpense) of $6,S1 and $3.respectively 6 (12) (29) $1million; current liabilities -$18 million; and exit costs -

Earnings (loss) from discontnued operations S6 $(8) S(24)

$4 million. The exit costs consist primarily of lease termination penalties and noncancelable lease payments made after certain leased properties are vacated. The During 2004, the Company recorded an additional tax gain pro forma results of operations reflecting the acquisition of approximately $6 million due to final tax adjustments related to the divestiture of NCNG. would not be materially different than the reported results of operations for 2003 or 2002.

The sale of ENCNG resulted in net proceeds of S7 million and a pre-tax loss of $2million, which is included in other, B. Acquisition of Natural Gas Reserves net on the Consolidated Statements of Income for the During 2003, Progress Fuels entered into several year ended December 31, 2003. independent transactions to acquire approximately 200 natural gas-producing wells with proven reserves of

5. ACQUISITIONS AND approximately 190 billion cubic feet (Bcf) from Republic BUSINESS COMBINATIONS Energy, Inc., and three other privately owned companies, all headquartered in Texas. The total cash purchase price A. Progress Telecommunications Corporation forthe transactions was $168 million. The pro forma results In December 2003, Progress Telecommunications of operations reflecting the acquisition would not be Corporation (PTC) and Caronet, Inc. (Caronet), both wholly materially different from the reported results of operations owned subsidiaries of Progress Energy, and EPIK for the years ended December 31,2003 and 2002.

Communications, Inc. (EPIK), awholly owned subsidiary of OdysseyTelecorp, Inc. (Odyssey), contributed substantially C. Wholesale Energy Contract Acquisition all of their assets and transferred certain liabilities to In May 2003, PVI entered into adefinitive agreement with Progress Telecom, LLC (PT LLC), a subsidiary of PTC. Williams Energy Marketing and Trading, a subsidiary of Subsequently, the stock of Caronet was sold to an affiliate The Williams Companies, Inc.,to acquire a long-term full-of Odyssey for $2 million in cash and Caronet became requirements power supply agreement at fixed prices a wholly owned subsidiary of Odyssey. Following with Jackson Electric Membership Corporation consummation of all the transactions described above, PTC (Jackson), located in Jefferson, Georgia. The agreement holds a 55% ownership interest in, and is the parent of, PT calls for a $188 million cash payment to Williams Energy LLC. Odyssey holds a combined 45% ownership interest in Marketing and Trading in exchange for assignment of the PT LLC through EPIK and Caronet The accounts of PT LLC Jackson supply agreement; the $188 million cash have been included in the Company's Consolidated payment was recorded as an intangible asset and is Financial Statements since the transaction date.

being amortized based on the economic benefit of the contract (See Note 9). The power supply agreement The transaction was accounted for as a partial terminates in 2015, with a first refusal right to extend for acquisition of EPIK through the issuance of the stock of a five years. The agreement includes the use of consolidated subsidiary. The contributions of PTC's and 640 megawatts (MW) of contracted Georgia System Caronet's net assets were recorded at their carrying generation comprised of nuclear, coal, gas and pumped-values of approximately $31 million. EPIK's contribution storage hydro resources. PVI expects to supplement the was recorded at its estimated fair value of $22 million acquired resources with open market purchases and using the purchase method. No gain or loss was with its own intermediate and peaking assets in Georgia recognized on the transaction. The EPIK purchase price to serve Jackson's forecasted 1,100 MW peak demand in was initially allocated as follows: property and equipment 2005 growing to a forecasted 1,700 MW demand by 2015.

- $27 million; other current assets - $9 million; current liabilities - $21 million; and goodwill - $7 million. During 2004, PT LLC developed a restructuring plan to exit certain leasing arrangements of EPIK and finalized its 68

Progress Energy Annual Report 2004 D. Westchester Acquisition Marketing, Inc., for each project and S23 million was assigned to interconnection contracts. Goodwill was In April 2002, Progress Fuels, a subsidiary of Progress assigned to the CCO segment and will be deductible for Energy, acquired 100% of Westchester Gas Company tax purposes.

(Westchester). During 2004 the name of the company was changed to Winchester Energy Co. Ltd. The acquisition The pro forma results of operations reflecting the included approximately 215 natural gas-producing wells, acquisition would not be materially different from the 52 miles of intrastate gas pipeline and 170 miles of gas- reported results of operations for the year ended gathering systems located within a 25-mile radius of December 31, 2002.

Jonesville, Texas, on the Texas-Louisiana border.

6. PROPERTY, PLANT AND EQUIPMENT The aggregate purchase price of approximately

$153 million consisted of cash consideration of A. Utility Plant approximately $22 million and the issuance of 2.5 million The balances of electric utility plant in service at shares of Progress Energy common stock then valued at December31 are listed below, with a range of depreciable approximately $129 million. The purchase price included lives for each:

approximately $2 million of direct transaction costs. The final purchase price was allocated to oil and gas (inmillions) 2004 2003 properties, intangible assets, diversified business Production plant 17-33 years) $11,966 S12,044 property, networking capital and deferred tax liabilities for Transmission plant (30-75 years) 2,282 2,167 approximatelySi52 million,$9 million,$32 million,$5 million Distribution plant (12-50 years) 6.749 6,432 and $45 million, respectively. The $9 million intangible General plant and other (8-75 years) 1.106 1,037 assets relates to customer contracts (See Note 9). Utility plant inservice $22103 $21,680 The acquisition has been accounted for using the Generally, electric utility plant at PEC and PEF, other than purchase method of accounting and, accordingly, the results of operations forWestchester have been included nuclear fuel, is pledged as collateral for the first in Progress Energy's Consolidated Financial Statements mortgage bonds of PEC and PEF, respectively.

since the date of acquisition. The pro forma results of operations reflecting the acquisition would not be AFUDC represents the estimated debt and equity costs materially different from the reported results of of capital funds necessary to finance the construction of operations for the year ended December 31,2002. new regulated assets. As prescribed in the regulatory uniform systems of accounts, AFUDC is charged to the E. Generation Acquisition cost of the plant. The equity funds portion of AFUDC is credited to other income, and the borrowed funds In February 2002, PVI acquired 100% of two electric portion is credited to interest charges. Regulatory generating projects located in Georgia from LG&E Energy authorities consider AFUDC an appropriate charge for Corp., a subsidiary of Powergen plc. The two projects inclusion in the rates charged to customers by the consist of 1) Walton County Power, LLC, in Monroe, utilities over the service life of the property. The Georgia, a 460 MW natural gas-fired plant placed in composite AFUDC rate for PEC's electric utility plant was service in June 2001 and 2) Washington County Power, LLC, in Washington County, Georgia, a 600 MW natural 7.2% in 2004, 4.0% in 2003 and 6.2% in 2002, respectively.

gas-fired plant placed in service in June 2003. The The composite AFUDC rate for PEF's electric utility plant Walton and Washington projects have been accounted was 7.8% in 2004, 2003 and 2002.

for using the purchase method of accounting and, accordingly, have been included in the Consolidated Depreciation provisions on utility plant, as a percent of Financial Statements since the acquisition date. average depreciable property otherthan nuclearfuel,were 2.2%, 2.5% and 2.6% in 2004, 2003 and 2002, respectively.

In the final allocation, the aggregate cash purchase price The depreciation provisions related to utility plant were of approximately S348 million was allocated to diversified $463 million, $517 million and $488 million in 2004, 2003 and business property, intangibles and goodwill for$228 million, 2002, respectively. In addition to utility plant depreciation

$56 million and S64 million, respectively (See Note 9). Of provisions, depreciation and amortization expense also the acquired intangible assets, $33 million was assigned includes decommissioning cost provisions, asset to tolling and power sale agreements with LG&E Energy retirement obligation (ARO) accretion, cost of removal 69

V Notes to Consolidated Financial Statements provisions (See Note 6D), regulatory approved expenses The synthetic fuel facilities are being depreciated through (See Note 8 and Note 22) and NC Clean Air Legislation 2007 when the Section 29 tax credits will expire. The amortization (See Note 8B). Company's nonregulated businesses capitalize interest costs under SFAS No.34, 'Capitalization of Interest Costs.'

During 2004, PEC met the requirements of both the During the years ended December 31,2004,2003 and 2002, NCUC and the SCPSC for the implementation of two respectively, the Company capitalized $7 million, depreciation studies that allowed the utility to reduce the $20 million and $38 million, respectively, of its interest cost rates used to calculate depreciation expense. The annual of $660 million, $655 million and $679 million. Capitalized reduction in depreciation expense is approximately interest for 2004 is related to the expansion of Fuels' gas

$82 million. The reduction is due primarily to extended operations. Capitalized interest in 2003 and 2002 is related lives at each of PEC's nuclear units. The new depreciation to the expansion of its nonregulated generation portfolio at rates were effective January 1,2004. PVI. Capitalized interest is included in diversified business property, net on the Consolidated Balance Amortization of nuclear fuel costs, including disposal costs Sheets. Diversified business depreciation expense associated with obligations to the U.S. Department of Energy was $148 million, $120 million and $85 million for (DOE) and costs associated with obligations to the DOE for December 31, 2004, 2003 and 2002, respectively.

the decommissioning and decontamination of enrichment facilities, for the years ended December 31, 2004,2003 and C. Joint Ownership of Generating Facilities 2002 were S140 million, S143 million and $141 million, PEC and PEF hold ownership interests in certain jointly respectively, and are included in fuel used for electric owned generating facilities. Each is entitled to shares of generation in the Consolidated Statements of Income. the generating capability and output of each unit equal to their respective ownership interests. Each also pays its B. Diversified Business Property ownership share of additional construction costs, fuel The balances of diversified business property at inventory purchases and operating expenses. PEC's and December 31 are listed below, with a range of PEF's share of expenses for the jointly owned facilities depreciable lives for each: is included in the appropriate expense category. The co-owner of Intercession City Unit P11 (P11) has (inmillions) 2004 2003 exclusive rights to the output of the unit during the Equipment (3-25 years) £383 £246 months of June through September. PEF has that right for Nonregulated generation plant and equipment (3-40 years) 1,302 1,299 the remainder of the year. PEC's and PEF's ownership interests in the jointly owned generating facilities are Land and mineral rights 107 93 listed on the following table with related information at Buildings and plants (5-40 years) 131 125 December 31 ($in millions):

Oil and gas properties (units-of-production) 336 412 Telecommunications equipment (5-20years) 80 63 Rail equipment (3-20 years) 29 125 Marine equipment (3-35 years) 87 83 Computers, office equipment and software (3-10 years) 36 36 Construction work in progress 26 13 Accumulated depreciation (507) (400)

Diversified business property, net $2.010 S2,095 70

Progress Energy Annual Report 2004 2004 Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress PEC Mayo Plant 83.83% 5516 S249 S1 PEC Harris Plant 83.83% 3,185 1.387 13 PEC Brunswick Plant 81.67% 1,624 888 28 PEC Roxboro Unit 4 87.06% 323 147 1 PEF Crystal River Unit 3 91.78% 889 443 9 PEF Intercession City Unit P11 66.67% 22 7 8 2003 Company Construction Ownership Plant Accumulated Work in Subsidiary Facility Interest Investment Depreciation Progress PEC Mayo Plant 83.83% S464 $242 550 PEC Harris Plant 83.83% 3,248 1,424 7 PEC Brunswick Plant 81.67% 1,611 885 21 PEC Roxboro Unit 4 87.06% 323 139 1 PEF Crystal River Unit 3 91.78% 875 442 46 PEF Intercession City Unit PI1 66.67% 22 6 6 In the tables above, plant investment and accumulated 8A). At December 31, 2004, such costs consist of removal depreciation are not reduced by the regulatory costs of $1.606 billion, removal costs for nonirradiated disallowances related to the Shearon Harris Nuclear areas at nuclear facilities of $131 million and amounts Plant (Harris Plant). previously collected for dismantlement of fossil generation plants of $144 million. At December 31, 2003, D. Asset Retirement Obligations such costs consist of removal costs of $1.846 billion, removal costs for nonirradiated areas at nuclearfacilities At December 31, 2004 and 2003, the asset retirement costs of $129 million and amounts previously collected for related to nuclear decommissioning of irradiated plant, net dismantlement of fossil generation plants of $143 million.

of accumulated depreciation, totaled $277 million and During 2004, PEC reduced its estimated removal costs to

$354 million, respectively. Funds set aside inthe Company's take into account the estimates used in the depreciation nuclear decommissioning trust funds for the nuclear studies implemented during 2004 (See Note 6A). This decommissioning liability totaled $1.044 billion and resulted in a downward revision in the PEC estimated

$938 million at December 31, 2004 and 2003, respectively.

removal costs and equal increase in accumulated Net nuclear decommissioning trust unrealized gains are depreciation of approximately $345 million.

included in regulatory liabilities (See Note 8A).

PEC's most recent site-specific estimates of Decommissioning cost provisions, which are included in depreciation and amortization expense, were $31 million in decommissioning costs were developed in 2004, using 2004 cost factors, and are based on prompt each of 2004, 2003 and 2002. Management believes that dismantlement decommissioning, which reflects the decommissioning costs that have been and will be cost of removal of all radioactive and other structures recovered through rates by PEC and PEF will be sufficient currently at the site, with such removal occurring after to provide for the costs of decommissioning. The operating license expiration. These estimates, in 2004 Company's expenses recognized for the disposal or dollars, are $294 million for Robinson Unit No. 2, removal of utility assets that are not SFAS No. 143 asset

$290 million for Brunswick Unit No. 1, $313 million for removal obligations, which are included in depreciation Brunswick Unit No. 2 and $359 million for the Harris and amortization expense, were $160 million, $158 million Plant. The estimates are subject to change based on a and $149 million in 2004, 2003 and 2002, respectively.

variety of factors including, but not limited to, cost escalation, changes in technology applicable to nuclear The utilities recognize removal, nonirradiated decommissioning and changes in federal, state or local decommissioning and dismantlement costs in regulatory regulations. The cost estimates exclude the portion liabilities on the Consolidated Balance Sheets (See Note attributable to North Carolina Eastern Municipal Power 71

V Notes to Consolidated Financial Statements Agency (Power Agency), which holds an undivided (inmillions) Regulated Nonregulated ownership interest in the Brunswick and Harris nuclear Asset retirement obligations generating facilities. NRC operating licenses held by PEC as of January 1,2003 S1,183 S10 currently expire in December 2014 and September 2016 Additions - 11 for Brunswick Units 2 and 1,respectively. An application Accretion expense 68 1 to extend these licenses 20 years was submitted in Deductions - (2)

October2004. The NRC operating license held by PECfor Asset retirement obligations the Harris Plant currently expires in October 2026. An as of December 31, 2003 1,251 20 application to extend this license 20 years is expected to Additions - 6 be submitted in the fourth quarter of 2006. On April 19, Accretion expense 73 2 2004, the NRC announced that it has renewed the Deductions (63) (7) operating license for PEC's Robinson Nuclear Plant Asset retirement obligations (Robinson) for an additional 20 years through July 2030. asofDecember31,2004 S1,261 $21 PEF's most recent site-specific estimate of The cumulative effect of initial adoption of this statement decommissioning costs for the Crystal River Nuclear related to nonregulated operations was $1 million Unit 3 (CR3) was developed in 2000 based on prompt of income, which is included in cumulative effect of dismantlement decommissioning. The estimate, in 2000 change in accounting principles, net of tax on the dollars, is $491 million and is subject to change based on Consolidated Statements of Income for the year ended the same factors as discussed above for PEC's December 31, 2003. Pro forma net income has not been estimates. The cost estimate excludes the portion presented for prior years because the pro forma attributable to other co-owners of CR3. The NRC application of SFAS No. 143 to prior years would result in operating license held by PEF for CR3 currently expires pro forma net income not materially different from the in December 2016. An application to extend this license actual amounts reported.

20 years is expected to be submitted in the first quarter of 2009. E. Insurance The Company has identified but not recognized AROs PEC and PEF are members of Nuclear Electric Insurance related to electric transmission and distribution and Limited (NEIL), which provides primary and excess telecommunications assets as the result of easements over insurance coverage against property damage to property not owned bythe Company. These easements are members' nuclear generating facilities. Underthe primary generally perpetual and require retirement action only program, each company is insured for$500 million at each upon abandonment or cessation of use of the property for of its respective nuclear plants. In addition to primary the specified purpose. The ARO is not estimable for such coverage, NEIL also provides decontamination, easements, as the Company intends to utilize these premature decommissioning and excess property properties indefinitely. Inthe eventthe Company decides to insurance with limits of $2.0 billion on the Brunswick abandon or cease the use of a particular easement, an ARO and Harris plants, and $1.1 billion on the Robinson Plant would be recorded at that time. and CR3.

The Company's nonregulated AROs relate to coal mine Insurance coverage against incremental costs of operations, synthetic fuel operations and gas production replacement power resulting from prolonged accidental of Progress Fuels.The related asset retirement costs, net outages at nuclear generating units is also provided of accumulated depreciation, totaled $10 million and through membership in NEIL Both PEC and PEF are S5 million at December 31, 2004 and 2003, respectively. insured under NEIL, following a 12-week deductible period, for 52 weeks in the amount of $3million per week The following table shows the changes to the asset at the Brunswick and Harris plants, $2.5 million per week retirement obligations. Additions relate primarily to at the Robinson Plant and $4.5 million per week at CR3.

additional reclamation obligations at coal mine An additional 110 weeks (71 weeks for CR3) of coverage operations of Progress Fuels. The deductions to is provided at 80% of the above weekly amounts.

regulated ARO related to PEC re-measuring the nuclear For the current policy period, the companies are decommissioning costs of irradiated plants to take into subject to retrospective premium assessments of account updated site-specific decommissioning cost up to approximately $29.3 million with respect to the studies, which are required by the NCUC every five years. primary coverage, S32.4 million with respect to the decontamination, decommissioning and excess property 72

Progress Energy Annual Report 2004 coverage, and $20.2 million for the incremental damage reserve pursuant to a regulatory order and may replacement power costs coverage, in the event covered defer losses in excess of the reserve (See Notes 3 and 8A).

losses at insured facilities exceed premiums, reserves, reinsurance and other NEIL resources. Pursuant to 7. CURRENT ASSETS regulations of the NRC, each company's property damage Receivables insurance policies provide that all proceeds from such insurance be applied, first, to place the plant in a safe and At December 31, receivables were comprised of:

stable condition after an accident and, second, to (inmillions) 2004 2003 decontaminate, before any proceeds can be used for Trade accounts receivable $689 $705 decommissioning, plant repair or restoration. Each Unbilled accounts receivable 271 293 company is responsible to the extent losses may exceed Notes receivable 98 61 limits of the coverage described above.

Other receivables 27 47 Both PEC and PEF are insured against public liability for a Unbilled other receivables 28 10 nuclear incident up to$10.8 billion per occurrence. Under Allowance for doubtful accounts receivable (29) (32) the current provisions of the Price Anderson Act, which Total receivables $1,084 $1,084 limits liability for accidents at nuclear power plants, each company, as an owner of nuclear units, can be assessed for a portion of any third-party liability claims arising from Income tax receivables and interest income receivables an accident at any commercial nuclear power plant in are not included in this classification.These amounts are the United States. Inthe event that public liability claims in prepaids and other current assets on the Consolidated from an insured nuclear incident exceed $300 million Balance Sheet.

(currently available through commercial insurers), each company would be subjectto pro rata assessments of up Inventory to $101 million for each reactor owned per occurrence. At December 31, inventory was comprised of:

Payment of such assessments would be made over time (inmillions) 2004 2003 as necessary to limit the payment in any one year to no Fuel for production $235 $210 more than $10 million per reactor owned. Congress could possibly approve revisions to the Price Anderson Act Inventoryforsale 230 167 during 2005 that could include increased limits and Materials and supplies 517 530 assessments per reactor owned. The final outcome of Total inventory $982 S907 this matter cannot be predicted at this time.

Under the NEIL policies, if there were multiple terrorism 8. REGULATORY MATTERS losses occurring within one year, NEIL would make A. Regulatory Assets and Liabilities available one industry aggregate limit of $3.2 billion, along with any amounts it recovers from reinsurance, As regulated entities, the utilities are subject to the government indemnity or other sources up to the limits provisions of SFAS No. 71. Accordingly, the utilities for each claimant. If terrorism losses occurred beyond record certain assets and liabilities resulting from the the one-year period, a new set of limits and resources effects of the ratemaking process that would not be would apply. For nuclear liability claims arising out of recorded under GAAP for nonregulated entities. The terrorist acts, the primary level available through utilities' ability to continue to meet the criteria for commercial insurers is now subject to an industry application of SFAS No. 71 may be affected in the future aggregate limit of S300 million. The second level of by competitive forces and restructuring in the electric coverage obtained through the assessments discussed utility industry. Inthe event that SFAS No. 71 no longer above would continue to apply to losses exceeding applied to a separable portion of the Company's

$300 million and would provide coverage in excess of any operations, related regulatory assets and liabilities would diminished primary limits due to the terrorist acts. be eliminated unless an appropriate regulatory recovery mechanism was provided. Additionally, these factors PEC and PEFself-insuretheirtransmission and distribution could result in an impairment of utility plant assets as lines against loss due to storm damage and other natural determined pursuant to SFAS No. 144.

disasters. PEF accrues S6 million annually to a storm 73

V Notes to Consolidated Financial Statements At December 31, the balances of regulatory assets PEC obtained SCPSC and NCUC approval of fuel factors (liabilities) were as follows: in annual fuel-adjustment proceedings. The NCUC approved an annual increase of $62 million, $20 million (inmillions) 2004 2003 and $46 million by orders issued in September 2004, 2003 Deferred fuel cost- current (Note SB and 8C) $229 $270 and 2002, respectively. The SCPSC approved PEC's Deferred fuel cost- long-term (Note BB and 8C) 107 47 petition each year and the changes were insignificant.

Deferred impact of ARO - PEC (Note 1D) 305 291 Income taxes recoverable through future rates 84 75 PEC filed with the SCPSC seeking permission to defer (Note 15) expenses incurred from the first quarter 2004 winter Loss on reacquired debt (Note 1D) 53 55 storm. The SCPSC approved PEC's request to defer the Deferred DOE enrichment facilities-related costs 16 24 costs and amortize them ratably over five years Storm deferral (Notes 3 and BB) 316 21 beginning in January 2005. Approximately $9 million Postretirement benefits (Note 17) 74 9 related to storm costs was deferred in 2004.

Other 109 76 Total long-term regulatory assets $1,064 S598 In October 2003, PEC filed with the NCUC seeking permission to defer expenses incurred from Hurricane Isabel and the February 2003 winter storms. In December Deferred energy conservation cost- current (8) (7) 2003,the NCUC approved PEC's requestto deferthe costs Non-ARO cost of removal (Note 6D) 11.881) (2,118) associated with Hurricane Isabel and the February 2003 Deferred impact of ARO (Note 1D) (221) (212) ice storm and amortize them over a period of five years.

Net nuclear decommissioning trust PEC charged approximately $24 million in 2003 from unrealized gains (Note 6D) (224) (204)

Hurricane Isabel and from ice storms to the deferred Postretirement benefits (Note 17B) (45) (211) account. PEC recognized $5 million and $3million of NC Storm reserve (Note 3) - (41) storm amortization during 2004 and 2003, respectively.

Clean air compliance (Note BB) (248) (74)

Other (35) (19) The NCUC and SCPSC have approved proposals to Total long-term regulatory liabilities 12.654) (2,879) accelerate cost recovery of PEC's nuclear generating Net regulatory liabiities $(1369) SI(Z08) assets beginning January 1,2000, and continuing through 2009. The aggregate minimum and maximum amounts of Except for portions of deferred fuel costs and deferred cost recovery are $530 million and $750 million, storm costs, all regulatory assets earn a return or the respectively. Accelerated cost recovery of these assets cash has not yet been expended, in which case the resulted in no additional expense in 2004 and 2003 and assets are offset by liabilities that do not incur a carrying additional depreciation expense of approximately cost. The Company expects to fully recover these assets $53 million in 2002. Total accelerated depreciation and refund the liabilities through customer rates under recorded through December 31, 2004, was $403 million.

current regulatory practice.

The North Carolina Clean Smokestacks Act enacted in B. PEC Retail Rate Matters June 2002 (NC Clean Air) requires state utilities to reduce emissions of nitrogen oxide (NOx) and sulfur dioxide As of December 31, 2004, PEC's North Carolina retail fuel (SO2) from coal-fired plants. The NCUC has allowed the costs were underrecovered by $145 million. This amount utilities to amortize and recover the costs associated is comprised of $117 million eligible for recovery in 2005 with meeting the new emission standards over a seven-and $28 million deferred from a 2001 order from the NCUC year period beginning January 1, 2003. The legislation that cannot be collected during 2005, and has therefore provides for significant flexibility in the amount of annual been classified as a long-term asset. PEC intends to amortization recorded, which allows the utilities to vary collect this amount by October 31, 2007.

the amount amortized within certain limits. This flexibility provides a utility with the opportunity to consider the On October 15, 2004, the SCPSC approved PEC's request impacts of other factors on its regulatory return on equity to leave fuel rates unchanged. The deferred fuel balance when setting the amortization amount for each year. PEC at December 31,2004, is $23 million. This amount is eligible recognized $174 million and $74 million of clean air for recovery in PECs 2005 South Carolina fuel review.

amortization during 2004 and 2003, respectively. This legislation freezes PEC's base rates in North Carolina for five years, subject to certain conditions (See Note 22).

74

Progress Energy Annual Report 2004 In conjunction with the FPC merger, PEC reached a 461 MW (summer rating). The estimated total in-service settlement with the Public Staff of the NCUC in which it cost of Hines Unit 4 is$286 million, and the unit is planned agreed to provide credits to its nonreal time pricing for commercial operation in December 2007. If the actual customers in the amounts of $3 million in 2002, $5million cost is less than the estimate, customers will receive the in 2003 and $6million in both 2004 and 2005. benefit of such cost underruns. Any costs that exceed this estimate will not be recoverable absent In conjunction with the acquisition of NCNG in 1999, PEC extraordinary circumstances as found by the FPSC in agreed not to seek a base retail electric rate increase in subsequent proceedings.

North Carolina and South Carolina through December 2004. The agreement not to seek a base retail electric See Note 3 for information on PEF's petition for storm rate increase in South Carolina was extended to cost recovery.

December 2005 in conjunction with regulatory approval to form a holding company. PEF RATE CASE SETTLEMENT The FPSC initiated a rate proceeding in 2001 regarding C. PEF Retail Rate Matters PEFs future base rates. In March 2002, the parties in On November 9, 2004, the FPSC approved PEF's PEF's rate case entered into a Stipulation and Settlement underrecovered fuel costs of S156 million for 2004, of Agreement (the Agreement) related to retail rate matters.

which PEF plans to defer $79 million until 2006 to mitigate The Agreement was approved by the FPSC in April 2002.

the impact on customers resulting from the need to also The Agreement is generally effective from May 2002 recover hurricane-related costs. Therefore, S79 million of through December 2005, provided, however, that if PEF's deferred fuel costs has been classified as a long-term base rate earnings fall below a 10% return on equity, PEF asset As of December31, 2004, PEF was underrecovered may petition the FPSC to amend its base rates.

in fuel costs by$168 million. The additional $12 million over and above the $156 million approved by the FPSC will be The Agreement provides that PEF will reduce its retail included in PEF's 2005 fuel filing. revenues from the sale of electricity by an annual amount of $125 million. The Agreement also provides that PEF will On June 29, 2004, the FPSC approved a Stipulation and operate under a Revenue Sharing Incentive Plan (the Settlement Agreement, executed on April 29, 2004, by Plan) through 2005, and thereafter until terminated by the PEF, the Office of Public Counsel and the Florida FPSC, that establishes annual revenue caps and sharing Industrial Power Users Group. The stipulation and thresholds. The Plan provides that retail base rate settlement resolved the issue pending before the FPSC revenues between the sharing thresholds and the retail regarding the costs PEF will be allowed to recover base rate revenue caps will be divided into two shares -

through its Fuel and Purchased Power Cost Recovery a 1/3 share to be received by PEF's shareholders, and a clause in 2004 and beyond for waterborne coal deliveries 2/3 share to be refunded to PEF's retail customers, by the Company's affiliated coal supplier, Progress Fuels provided, however, that for the year 2002 only, the refund Corporation. The settlement sets fixed per ton prices to customers was limited to 67.1% of the 2/3 customer based on point of origin for all waterborne coal deliveries share. The retail base rate revenue sharing threshold in 2004, and establishes a market-based pricing amounts for 2004, 2003 and 2002 were S1.370 billion, methodology for determining recoverable waterborne $1.333 billion and $1.296 billion, respectively, and will coal transportation costs through a competitive increase $37 million in 2005. The Plan also provides that solicitation process or market price proxies in 2005 and all retail base rate revenues above the retail base rate thereafter. The settlement reduces the amount that PEF revenue caps established for each year will be refunded will charge to the Fuel and Purchased Power Cost to retail customers on an annual basis. For 2002, the Recovery clause for waterborne transportation by refund to customers was limited to 67.1% of the retail approximately $11 million beginning in 2004. base rate revenues that exceeded the 2002 cap. The retail base revenue caps for 2004, 2003 and 2002 were On November 3, 2004, the FPSC approved PEF's petition $1.430 billion, $1.393 billion and $1.356 billion, for Determination of Need for the construction of afourth respectively, and will increase $37 million in 2005. Any unit at PEF's Hines Energy Complex. Hines Unit 4 is amounts above the retail base revenue caps will be needed to maintain electric system reliability and refunded 100% to customers. At December 31, 2004, integrity and to continue to provide adequate electricity $9million has been accrued and will be refunded to retail to its ratepayers at a reasonable cost Hines Unit 4 will be customers by March 2005. The 2003 revenue sharing a combined cycle unit with a generating capacity of amount was S18 million, and was refunded to customers 75

V Notes to Consolidated Financial Statements by April 30, 2004. Approximately $5 million was originally projected test period for setting new base rates. The returned in March 2003 related to 2002 revenue sharing. requestfor increased base rates is based onthefactthat However, in February 2003, the parties to the Agreement PEF has faced significant cost increases over the past filed a motion seeking an order from the FPSC to enforce decade and expects its operational costs to continue to the Agreement In this motion, the parties disputed PEF's increase. These costs include the costs associated with calculation of retail revenue subject to refund and completion of the Hines Unit 3 generation facility, contended that the refund should be approximately extraordinary hurricane damage costs including capital

$23 million. In July 2003, the FPSC ruled that PEF must costs which are not expected to be directly recoverable, provide an additional $18 million to its retail customers the need to replenish the depleted storm reserve and the related to the 2002 revenue sharing calculation. PEF expected infrastructure investment necessary to meet recorded this refund in the second quarter of 2003 as a high customer expectations, coupled with the demands charge against electric operating revenue and refunded placed on PEF as a result of its strong customer growth.

this amount by October 2003. On February 7, 2005, the FPSC acknowledged receipt of PEF's notice and authorized minimum filing requirements The Agreement also provides that beginning with the and testimony to be filed May 1,2005.

in-service date of PEF's Hines Unit 2 and continuing through December 2005, PEF will be allowed to recover through the fuel cost recovery clause a return on average D. Regional Transmission Organizations and investment and depreciation expense for Hines Unit 2, to Standard Market Design the extent such costs do not exceed the unit's cumulative In 2000, the FERC issued Order No. 2000 regarding regional fuel savings over the recovery period. Hines Unit 2 is a transmission organizations (RTOs). This Order set minimum 516 MW combined-cycle unit that was placed in service characteristics and functions that RTOs must meet, in December 2003. PEF recovered $36 million through this including independent transmission service. In July 2002, clause related to Hines Unit 2.

the FERC issued its Notice of Proposed Rulemaking in Docket No. RM01 000, Remedying Undue Discrimination In addition, PEF suspended retail accruals on its reserves through Open Access Transmission Service and Standard for nuclear decommissioning and fossil dismantlement Electricity Market Design (SMD NOPR). If adopted as through December 2005. Additionally, for each calendar proposed, the rules set forth in the SMD NOPR would have year during the term of the Agreement, PEF will record a materially altered the manner in which transmission and

$63 million depreciation expense reduction and may, at generation services are provided and paid for. InApril 2003, its option, record up to an equal annual amount as an the FERC released a White Paper on the Wholesale Market offsetting accelerated depreciation expense. No Platform. The White Paper provided an overview of what accelerated depreciation expense was recorded during the FERC intended to include in a final rule in the SMD 2004 and 2003. In addition, PEF is authorized, at its NOPR docket The White Paper retained the fundamental discretion, to accelerate the amortization of certain and most protested aspects of SMD NOPR, including regulatory assets over the term of the Agreement mandatory RTOs and the FERC's assertion of jurisdiction over certain aspects of retail service. The FERC has not yet Under the terms of the Agreement, PEF agreed to continue issued a final rule on SMD NOPR. The Company cannot the implementation of its four-year Commitment to predictthe outcome of these matters orthe effectthatthey Excellence Reliability Plan and expected to achieve a 20%

may have on the GridSouth and GridFlorida proceedings improvement in its annual System Average Interruption currently ongoing before the FERC. By order issued Duration Index by no later than 2004. If this improvement December 22, 2004, the FERC terminated a portion of the level was not achieved for calendar years 2004 or 2005, proceedings regarding GridSouth. The GridSouth PEF would have provided a refund of $3 million for each Companies asked the FERC for further clarification as to the year the level is not achieved to 10% of its total retail portions of the GridSouth docket it intended to address. On customers served by its worst performing distribution March 2, 2005, the FERC affirmed that it only intended to feeder lines. PEF achieved this improvement level in 2004.

close the mediation portion of the GridSouth docket It is unknown what impact the future proceedings will have on In January 2005, in anticipation of the expiration of its the Company's earnings, revenues or prices.

Stipulation and Settlement approved by the FPSC in 2002 to conclude PEF's then-pending rate case, PEF notified The FPSC ruled in December 2001 that the formation of the FPSC that it intends to request an increase in its base GridFlorida by the three major investor-owned utilities in rates, effective January 1, 2006. In its notice, PEF Florida, including PEF, was prudent but ordered changes in requested the FPSC to approve calendar year 2006 as the 76

Progress Energy Annual Report 2004 the structure and market design of the proposed wholesale sales in peninsular Florida. Given the difficulty organization. In September 2002, the FPSC set a hearing PEC believes it would experience in passing one of the for market design issues; this order was appealed to the interim screens, on August 12, 2004, PEC notified the FERC Florida Supreme Court by the consumer advocate of the that it would revise its Market-based Rate tariff to restrict state of Florida. In June 2003, the Florida Supreme Court it to sales outside PEC's control area and file a new cost-dismissed the appeal without prejudice. In September based tariff for sales within PEC's control area that 2003, the FERC held a Joint Technical Conference with the incorporates the FERC's default cost-based rate FPSC to consider issues related to formation of an RTO for methodologies for sales of one year or less. PEC peninsular Florida. In December 2003, the FPSC ordered anticipates making this filing in the first quarter of 2005.

further state proceedings and established a collaborative PEC does not anticipate that the current operations will be workshop process to be conducted during 2004. In June materially impacted bythis change. Although the Company 2004, the workshop process was abated pending cannot predictthe ultimate outcome of these changes, the completion of a cost-benefit study currently scheduled to Company does not anticipate that the current operations be presented at a FPSC workshop on May 25, 2005, with of PEC or PEF would be impacted materially if they were subsequent action by the FPSC to be thereafter unable to sell power at market-based rates in their determined. respective control areas.

The Company has $33 million and $4 million invested in F. Energy Delivery Capitalization Practice GridSouth and GridFlorida, respectively, related to startup The Company has reviewed its capitalization policies for costs at December 31, 2004. The Company expects to its Energy Delivery business units in PEC and PEF That recover these startup costs in conjunction with the review indicated that in the areas of outage and GridSouth and GridFlorida original structures or in emergency work not associated with major storms and conjunction with any alternate combined transmission allocation of indirect costs, both PEC and PEF should structures that emerge. revise the way that they estimate the amount of capital costs associated with such work. The Company has E. FERC Market Power Mitigation implemented such changes effective January 1, 2005, A FERC order issued in November 2001 on certain which include more detailed classification of outage and unaffiliated utilities' triennial market-based wholesale emergency work and result in more precise estimation power rate authorization updates required certain and a process of retesting accounting estimates on an mitigation actions thatthose utilities would need to take for annual basis. As a result of the changes in accounting sales/purchases within their control areas and required estimates for the outage and emergency work and those utilities to post information on their Web sites indirect costs, a lesser proportion of PECs and PEFs regarding their power systems' status. As a result of a costs will be capitalized on a prospective basis. The request for rehearing filed by certain market participants, Company estimates that the combined impact for both FERC issued an order delaying the effective date of the utilities in 2005 will be that approximately $55 million of mitigation plan until after a planned technical conference costs that would have been capitalized under the on market power determination. In December 2003, the previous policies will be expensed. Pursuant to SFAS FERC issued astaff paper discussing alternatives and held No. 71, PEC and PEF have informed the state regulators a technical conference in January 2004. InApril 2004, the having jurisdiction over them of this change and thatthe FERC issued two orders concerning utilities' ability to sell new estimation process will be implemented effective wholesale electricity at market-based rates. In the first January 1, 2005. The Company has also requested a order, the FERC adopted two new interim screens for method change from the IRS.

assessing potential generation market power of applicants for wholesale market-based rates, and described 9. GOODWILL AND OTHER additional analyses and mitigation measures that could be INTANGIBLE ASSETS presented if an applicant does not pass one of these interim screens. In July 2004, the FERC issued an order on The Company performed the annual goodwill impairment rehearing affirming its conclusions in the April order. Inthe test in accordance with FASB Statement No. 142, second order, the FERC initiated a rulemaking to consider Goodwill and Other Intangible Assets,' for the CCO whether the FERC's current methodology for determining segment in the first quarter of 2004, and the annual whether a public utility should be allowed to sell wholesale goodwill impairment test for the PEC Electric and PEF electricity at market-based rates should be modified in any segments in the second quarter of 2004, each of which way. PEF does not have market-based rate authority for indicated no impairment.

77

V Notes to Consolidated Financial Statements The changes in the carrying amount of goodwill, by economic benefits of the contracts (See Notes 5C and reportable segment, are as follows: 5D). Other intangibles are primarily acquired customer PEC Corporate contracts and permits that are amortized over their (inmillions) Electric PEF CCO and Other Total respective lives. Of the increase in other intangible Balance as of assets, $24 million resulted from the minimum pension January 1.2003 S1.922 $1,733 S64 S- $3,719 liability adjustment at December 31, 2004 (See Note 17).

Acquisitions - - - 7 7 Balance as of Amortization expense recorded on intangible assets for December31,2003 $1,922 $1.733 S64 S7 $3,726 the years ended December 31, 2004, 2003 and 2002 was, Purchase accounting in millions, $42, $37 and $33, respectively. The estimated adjustment - - - 17) (7) annual amortization expense for intangible assets for Balance as of 2005 through 2009, in millions, is approximately $35, $36, December3l.2004 $1,922 $1,733 S64 $- S3.719 $36, $18 and $18, respectively.

In December 2003, $7 million in goodwill was recorded 10. IMPAIRMENTS OF LONG-LIVED ASSETS based on a preliminary purchase price allocation as part AND INVESTMENTS of the Progress Telecommunications Corporation partial acquisition of EPIK and was reported in the Corporate The Companyapplies SFAS No.144forthe accounting and and Other segment The Company revised the preliminary reporting of impairment or disposal of long-lived assets. In 2003 and 2002, the Company recorded pre-tax long-lived EPIK purchase price allocation as of September 2004, and the $7 million of goodwill was reallocated to certain asset and investment impairments and other charges of tangible assets acquired based on the results of approximately $38 million and $414 million, respectively.

valuations and appraisals (See Note 5A).

A. Long-Lived Assets The gross carrying amount and accumulated Due to the reduction in coal production, the Company amortization of the Company's intangible assets at evaluated Kentucky May coal mine's long-lived assets in December 31 are as follows: 2003. Fair value was determined based on discounted 2004 2003 cash flows. As a result of this review, the Company Gross Gross recorded asset impairments of $17 million on a pre-tax Carrying Accumulated Carrying Accumulated basis during the fourth quarter of 2003.

(inmillions) Amount Amortization Amount Amortization Synthetic fuel An estimated impairment of assets held for sale of intangibles $134 S(80) $140 $(64) $59 million is included in the 2002 amount, which relates Power to Railcar Ltd. (See Note 4C).

agreements acquired 221 (39) 221 (20)

Other 119 (18) 93 (13)

Due to the decline of the telecommunications industry and continued operating losses, the Company initiated an Total $474 5(137) $454 $(97) independent valuation study during 2002 to assess the recoverability of the long-lived assets of PTC and In June 2004, the Company sold, in two transactions, a Caronet. Based on this assessment, the Company combined 49.8% partnership interest in Colona Synfuel recorded asset impairments of $305 million on a pre-tax Limited Partnership, LLLP, one of its synthetic fuel operations. basis and other charges of $25 million on a pre-tax basis Approximately $6million in synthetic fuel intangibles and primarily related to inventory adjustments in the third

$3 million in related accumulated amortization were quarter of 2002. This write-down constitutes a significant included in the basis of the partnership interest sold. reduction in the book value of these long-lived assets.

All of the Company's intangibles are subject to The long-lived asset impairments include an impairment of amortization. Synthetic fuel intangibles represent property, plant and equipment, construction work in intangibles for synthetic fuel technology. These process and intangible assets. The impairment charge intangibles are being amortized on a straight-line basis represents the difference between the fair value and until the expiration of tax credits under Section 29 of the carrying amount of these long-lived assets. The fair value Internal Revenue Code (Section 29) in December 2007 of these assets was determined using a valuation study (See Note 23E). The intangibles related to power heavilyweighted onthe discounted cash flow methodology, agreements acquired are being amortized based on the using market approaches as supporting information.

78

Progress Energy Annual Report 2004 B. Investments B. Stock-Based Compensation The Company continually reviews its investments to EMPLOYEE STOCK OWNERSHIP PLAN determine whether a decline in fair value below the cost The Company sponsors the Progress Energy 401(k) Savings basis is other than temporary. In 2003, PEC's affordable and Stock Ownership Plan (401(k)) for which substantially housing investment (AHI) portfolio was reviewed and all full-time nonbargaining unit employees and certain part-deemed to be impaired based on various factors time nonbargaining unit employees within participating including continued operating losses of the AHI portfolio subsidiaries are eligible. Participating subsidiaries within and management performance issues arising at certain the Company as of January 1,2003, were PEC, PEF, PTC, properties within the AHI portfolio. As a result, PEC Progress Fuels (Corporate) and Progress Energy Service recorded an impairment of $18 million on a pre-tax basis Company. Effective December 19, 2003, (the PT LLC/EPIK during the fourth quarter of 2003. PEC also recorded an merger date), PTC no longer participates in the 401(k) plan.

impairment of $3million for a cost investment. The 401(k), which has Company matching and incentive goal features, encourages systematic savings by In May 2002, Interpath Communication, Inc., merged with a employees and provides a method of acquiring Company third party. As a result, the Company reviewed the Interpath common stock and other diverse investments. The 401(k),

investment for impairment and wrote off the remaining as amended in 1989, isan Employee Stock Ownership Plan amount of its cost-basis investment in Interpath, recording (ESOP) that can enter into acquisition loans to acquire a pre-tax impairment of $25 million in the third quarter of Company common stock to satisfy 401(k) common share 2002. In the fourth quarter of 2002, the Company sold its needs. Qualification as an ESOP did not change the level of remaining interest in Interpath for a nominal amount. benefits received by employees under the 401(k). Common stock acquired with the proceeds of an ESOP loan is held

11. EQUITY by the 401(k) Trustee in a suspense account. The common A. Common Stock stock is released from the suspense account and made available for allocation to participants as the ESOP loan is At December 31, 2004, the Company had approximately repaid. Such allocations are used to partially meet common 63 million shares of common stock authorized by the stock needs related to Company matching and incentive Board of Directors that remained unissued and reserved, contributions and/or reinvested dividends. All or a portion primarily to satisfy the requirements of the Company's of the dividends paid on ESOP suspense shares and on stock plans. In 2002, the Board of Directors authorized ESOP shares allocated to participants may be used to meeting the requirements of the Progress Energy 401(k) repay ESOP acquisition loans. To the extent used to repay Savings and Stock Ownership Plan and the Investor Plus such loans, the dividends are deductible for income tax Stock Purchase Plan with original issue shares. During purposes. Also, beginning in 2002, the dividends paid on 2004, 2003 and 2002, respectively, the Company issued ESOP shares that are either paid directly to participants or approximately 1 million, 8 million and 2 million shares used to purchase additional shares, which are then under these plans for net proceeds of approximately allocated to participants, are fully deductible for income

$62 million, $305 million and $86 million. The Company continues to meet the requirements of the restricted tax purposes.

stock plan with issued and outstanding shares.

There were 3.5 million and 4.0 million ESOP suspense shares at December 31, 2004 and 2003, respectively, with In November 2002, the Company issued 14.7 million a fair value of $156 million and $183 million, respectively.

shares of common stock for net cash proceeds of ESOP shares allocated to plan participants totaled approximately $600 million, which were primarily used to 12.6 million and 13.1 million at December 31, 2004 and retire commercial paper. In April 2002, the Company issued 2.5 million shares of common stock, valued at 2003, respectively. The Company's matching and incentive goal compensation cost under the 401(k) is approximately $129 million, in conjunction with the determined based on matching percentages and purchase of Westchester (See Note 5D).

incentive goal attainment as defined in the plan. Such There are various provisions limiting the use of retained compensation cost is allocated to participants' accounts in the form of Company common stock, with the number earnings for the payment of dividends under certain of shares determined by dividing compensation cost by circumstances. At December 31, 2004, there were no the common stock market value atthe time of allocation.

significant restrictions on the use of retained earnings.

The Company currently meets common stock share needs with open market purchases, with shares 79

V Notes to Consolidated Financial Statements released from the ESOP suspense account and with granted by the Company equals the market price at grant newly issued shares. Costs for incentive goal date and, accordingly, no compensation expense has compensation are accrued during the fiscal year and been recognized for any options granted during 2004, typically paid in shares in the following year, while costs 2003 and 2002. The Company will begin expensing stock for the matching component are typically met with options on July 1,2005, based on SFAS No. 123R (See shares in the same year incurred. Matching and Note 2). In 2004, however, the Company made the incentive costs, which were met and will be met with decision to cease granting stock options and intends to shares released from the suspense account, totaled replace that compensation program with other approximately $21 million, $20 million and $20 million for programs. Therefore, the amount of stock option the years ended December 31, 2004, 2003 and 2002, expense expected to be recorded in 2005 is below the respectively. Total matching and incentive cost totaled amount that would have been recorded if the stock approximately $32 million, $35 million and $30 million for option program had continued.

the years ended December 31, 2004, 2003 and 2002, respectively. The Company has a long-term note The pro forma information presented in Note 1 regarding receivable from the 4011k) Trustee related to the net income and earnings per share is required by SFAS purchase of common stock from the Company in 1989. No. 148. Under this statement, compensation cost is The balance of the note receivable from the 401(k) measured atthe grant date based onthe fairvalue of the Trustee is included in the determination of unearned award and isrecognized overthe vesting period. The pro ESOP common stock, which reduces common stock forma amounts presented in Note 1 have been equity. ESOP shares that have not been committed to be determined as if the Company had accounted for its released to participants' accounts are not considered employee stock options under SFAS No. 123. The fair outstanding for the determination of earnings per value for these options was estimated at the date of common share. Interest income on the note receivable grant using a Black-Scholes option pricing model with and dividends on unallocated ESOP shares are not the following weighted-average assumptions:

recognized for financial statement purposes.

2004 2003 2002 Risk-free interest rate 4.22% 4.25% 4.14%

STOCK OPTION AGREEMENTS Dividend yield 5.19% 4.75% 5.20%

Pursuant to the Company's 1997 Equity Incentive Plan Volatility factor 20.30% 22.28% 24.98%

and 2002 Equity Incentive Plan, amended and restated as Weighted-average expected life of July 10, 2002, the Company may grant options to of the options (in years) 10 10 10 purchase shares of common stock to directors, officers and eligible employees for up to 5 million and 15 million shares, respectively. Generally, options granted to The option valuation model requires the input of employees vest one-third per year with 100% vesting at highly subjective assumptions, primarily stock price volatility, changes in which can materially affect the fair the end of year three, while options granted to directors vest 100% at the end of one year. The options expire value estimate.

10 years from the date of grant. All option grants have an exercise price equal to the fair market value of the The options outstanding at December 31, 2004, 2003 and Company's common stock on the grant date. The 2002 had a weighted-average remaining contractual life Company measures compensation expense for stock of 7.6, 8.7 and 9.3 years, respectively, and had exercise options as the difference between the market price of its prices that ranged from $40.41 to $51.85. The tabular common stock and the exercise price of the option atthe information forthe option activity is as follows:

grant date. The exercise price at which options are 80

Progress Energy Annual Report 2004 2004 2003 2002 Weighted- Weighted- Weighted-Average Average Average Number of Exercise Number of Exercise Number of Exercise (option quantities in millions) Options Price Options Price Options Price Options outstanding, January 1 8.0 $43.54 5.2 $42.84 2.3 S43.49 Granted - - 3.0 $44.70 2.9 S42.34 Forfeited (0.1) S.76 (0.1) $43.64 - $43.71 Canceled (0.1) $43.67 (0.1) $43.62 - -

Exercised (0.4) $42.82 - $43.00 - -

Options outstanding, December31 7.4 $43.57 8.0 $43.54 5.2 S42.84 Options exercisable, December 31 with a remaining contractual life of 7.6 years 4.6 $43.35 2.4 $43.09 0.8 $43.49 Weighted-average grant date fair value of options granted during the year - S7.16 $6.83 OTHER STOCK-BASED COMPENSATION PLANS $44.27 in 2004, 2003 and 2002, respectively. Compensation expense is reduced by any forfeitures. Restricted shares The Company has additional compensation plans for are not included as shares outstanding in the basic officers and key employees of the Company that are stock-earnings per share calculation until the shares are no based in whole or in part. The two primary active longer forfeitable. Changes in restricted stock shares stock-based compensation programs are the Performance outstanding were:

Share Sub-Plan (PSSP) and the Restricted Stock Awards program (RSA), both of which were established pursuantto 2004 2003 2002 the Company's 1997 Equity Incentive Plan and were Beginning balance 944.883 950,180 674,511 continued under the Company's 2002 Equity Incentive Plan, Granted 154.500 180,200 365,920 as amended and restated as of July 10, 2002. Vested (367,107) 1151,677) (75,200)

Forfeited (87,100) (33,820) (15,051)

Under the terms of the PSSP, officers and key employees Ending balance 645.176 944,883 950,180 of the Company are granted performance shares on an annual basis that vest over a three-year consecutive The total amount expensed for other stock-based period. Each performance share has a value that isequal compensation plans was $10 million, $27 million and to, and changes with, the value of a share of the

$17 million in 2004, 2003 and 2002, respectively.

Company's common stock, and dividend equivalents are accrued on, and reinvested in, the performance shares.

C. Earnings Per Common Share The PSSP has two equally weighted performance measures, both of which are based on the Company's Basic earnings per common share is based on the results as compared to a peer group of utilities. weighted-average number of common shares Compensation expense is recognized over the vesting outstanding. Diluted earnings per share includes the period based on the expected ultimate cash payout and effect of the nonvested portion of restricted stock awards is reduced by any forfeitures. Effective January 1,2005, and the effect of stock options outstanding.

new awards granted pursuant to the PSSP will be payable in Company common stock rather than in cash. A reconciliation of the weighted-average number of common shares outstanding for basic and dilutive The RSA program allows the Company to grant shares of purposes is as follows:

restricted common stock to officers and key employees of (inmillions) 2004 2003 2002 the Company. The restricted shares generally vest on a Weighted-average common graded vesting schedule over a minimum of three years. shares - basic 242.2 237.2 217.2 Compensation expense, which is based on the fair value Restricted stock awards .8 1.0 .8 of common stock at the grant date, is recognized over the .1 - .2 Stock options applicable vesting period, with corresponding increases Weighted-average shares -

in common stock equity. The weighted-average price of fully diluted 243.1 238.2 218.2 restricted shares at the grant date was $46.95, $39.53 and 81

V Notes to Consolidated Financial Statements There are no adjustments to net income or to income 12. PREFERRED STOCK OF from continuing operations between the calculations of SUBSIDIARIES - NOT SUBJECT basic and fully diluted earnings per common share. TO MANDATORY REDEMPTION ESOP shares that have not been committed to be released to participants' accounts are not considered outstanding for the determination of earnings per All of the Company's preferred stock was issued by its common share. The weighted-average of these shares subsidiaries and was not subjectto mandatory redemption.

totaled 3.6 million, 4.1 million and 4.8 million for the years Preferred stock outstanding at December 31, 2004 and ended December 31, 2004, 2003 and 2002, respectively. 2003 consisted of the following:

There were 3.0 million, 5.3 million and 92 thousand stock (inmillions, except share data and par value) options outstanding at December 31,2004,2003 and 2002, Progress Energy Carolinas, Inc.

respectively, which were not included in the weighted- Authorized -

average number of shares for computing the fully diluted 300,000 shares, cumulative, $100 par value Preferred Stock; earnings per share because they were antidilutive. 20,000,000 shares, cumulative, S100 par value Serial Preferred Stock

$5.00 Preferred -236,997 shares outstanding $24 D. Accumulated Other Comprehensive Loss (redemption price $110.00)

Components of accumulated other comprehensive loss $4.20 Serial Preferred -100,000 shares outstanding 10 are as follows: (redemption price $102.00)

$5.44 Serial Preferred -249,850 shares outstanding 25 tin millions) 2004 2003 (redemption price $101.00)

Loss on cash flow hedges S(28) $136)

$59 Minimum pension liability adjustments (142) (16)

Progress Energy Florida, Inc.

Foreign currency translation and other 6 2 Authorized -

Total accumulated other comprehensive loss S(164) $(50) 4,000,000 shares, cumulative,

$100 par value Preferred Stock; 5,000,000 shares, cumulative, no par value Preferred Stock; 1,000,000 shares, $100 par value Preference Stock;

$100 par value Preferred Stock:

4.00% - 39,980 shares outstanding $4 (redemption price $104.25) 4.40% - 75,000 shares outstanding 8 (redemption price S10200) 4.58% - 99,990 shares outstanding 10 (redemption price S101.00) 4.60% - 39,997 shares outstanding 4 (redemption price S103.25) 4.75% - 80,000 shares outstanding 8 (redemption price S102.00)

$34 Total Preferred Stock of Subsidiaries $93 82

Progress Energy Annual Report 2004

13. DEBT AND CREDIT FACILITIES A. Debt and Credit Facilities At December 31, the Company's long-term debt consisted of the following (maturities and weighted-average interest rates at December 31, 2004):

(inmillions) 2004 2003 Progress Energy, Inc.

Senior unsecured notes, maturing 2006-2031 6.90% $4,300 $4,800 Draws on revolving credit agreement expiring 2009 3.19% 160 Unamortized fair value hedge gain, net 12 19 Unamortized premium and discount net (23) (27) 4,449 4,792 Progress Energy Carolinas, Inc.

First mortgage bonds, maturing 2005-2033 6.33% 1,600 1,900 Pollution control obligations, maturing 2017-2024 1.98% 669 708 Unsecured notes, maturing 2012 6.50% 500 500 Medium-term notes, maturing 2008 6.65% 300 300 Unamortized premium and discount net (19) (22) 3,050 3,386 Progress Energy Florida, Inc.

First mortgage bonds, maturing 2008-2033 5.60% 1,330 1,330 Pollution control obligations, maturing 2018-2027 1.67% 241 241 Medium-term notes, maturing 2005-2028 6.76% 337 379 Draws on revolving credit agreement expiring 2006 2.95% 55 Unamortized premium and discount net (3) (3) 1,960 1,947 Florida Progress Funding Corporation (See Note 19)

Debt to affiliated trust maturing 2039 7.10% 309 309 Unamortized premium and discount net (39) (39) 270 270 Progress Capital Holdings, Inc.

Medium-term notes, maturing 2006-2008 6.84% 140 165 Miscellaneous notes 1 1 141 166 Progress Genco Ventures, LLC Variable rate project financing, maturing 2007 - 241 Current portion of long-term debt (349) (868)

Total long-term debt $9,521 $9,934 At December 31, 2004, the Company had committed lines facilities classified as short-term obligations at a of credit used to support its commercial paper weighted-average interest rate of 3.18%. No amount was borrowings. The Progress Energy five-year credit facility outstanding under the Company's committed lines of and the PEF three-year credit facility are included in credit at December 31, 2003. The Company is required to long-term debt. All other credit facilities are included in pay minimal annual commitment fees to maintain its short-term obligations. At December 31, 2004, the credit facilities.

Company had $260 million outstanding under its credit 83

V Notes to Consolidated Financial Statements The following table summarizes the Company's credit facilities:

tin millions)

Company Description Total Outstanding Available Progress Energy, Inc. 5-Year (expiring 8/5109) S1,130 $160 $970 Progress Energy Carolinas, Inc. 364-Day (expiring 7/27/05) 165 90 75 Progress Energy Carolinas, Inc. 3-Year (expiring 7/31/05) 285 - 285 Progress Energy Florida, Inc. 364-Day (expiring 3/29/05) 200 170 30 Progress Energy Florida, Inc. 3-Year (expiring 4/01/06) 200 55 145 Less: amounts reserved(a) (574)

Total credit facilities S1,980 $475 S931 TaTTo the extent amounts are reserved for commercial paper outstanding or backing letters of credit, they are not available for additional borrowings.

At December 31, 2004 and 2003, the Company had Company's ability to borrow under these facilities. These

$424 million and $4 million, respectively, of outstanding include maximum debt to total capital ratios, interest commercial paper and other short-term debt classified as coverage tests, material adverse change clauses and short-term obligations. The weighted-average interest cross-default provisions.

rates of such short-term obligations at December 31, 2004 and 2003 were 2.77% and 2.25%, respectively. At All of the credit facilities include a defined maximum total December31,2004, the Company has reserved $150 million debt to total capital ratio. At December 31, 2004, the of its lines of credit for backing of letters of credit maximum and calculated ratios for the companies, pursuant to the terms of the agreements, are as follows:

Both Progress Energy and PEF have an uncommitted Company Maximum Ratio Actual Ratio(a) bank bid facility authorizing them to borrow and Progress Energy, Inc. 65% 60.7%

reborrow, and have loans outstanding at any time, up to Progress Energy Carolinas, Inc. 65% 52.3%

$300 million and $100 million, respectively. These bank bid facilities were not drawn at December 31, 2004. Progress Energy Florida, Inc. 65% 50.8%

1a3lndebtedness as defined by the bank agreements includes certain letters of credit and guarantees that are not recorded on the Consolidated On January 31, 2005, Progress Energy, Inc., entered into a Balance Sheets.

new $600 million revolving credit agreement, which expires December 30, 2005. This facility was added to Progress Energy's 364-day credit facility and both PEF's provide additional liquidity during 2005 due in part to 364-day and three-year credit facilities have a financial storm restoration costs incurred in Florida during 2004. covenant for interest coverage. The covenants require The credit agreement includes a defined maximum total Progress Energy's and PEF's earnings before interest, debt to total capital ratio of 68% and a minimum interest taxes, and depreciation and amortization to interest coverage ratio of 2.5 to 1. The credit agreement also expense ratio to be at least 2.5 to 1 and 3 to 1, contains various cross-default and other acceleration respectively. For the year ended December 31, 2004, the provisions. On February 4,2005, S300 million was drawn ratios were 4.00 to 1 and 7.93 to 1 for the Company and under the new facility to reduce commercial paper and PEF, respectively.

bank loans outstanding.

In March 2005, Progress Energy, Inc.'s five-year credit The combined aggregate maturities of long-term debt facility was amended to increase the maximum total debt for 2005 through 2009 are approximately $349 million, to total capital ratio from 65% to 68% in anticipation of the S963 million, $674 million, $827 million and $560 million, potential impacts of proposed accounting rules for respectively. uncertain tax positions. See Notes 2 and 23E.

B. Covenants and Default Provisions MATERIAL ADVERSE CHANGE CLAUSE FINANCIAL COVENANTS The credit facilities of Progress Energy, PEC, and PEF include a provision under which lenders could refuse to Progress Energy's, PEC's and PEF's credit lines contain advance funds in the event of a material adverse change various terms and conditions that could affect the (MAC) in the borrower's financial condition. Pursuant to 84

Progress Energy Annual Report 2004 the terms of Progress Energy's five-year credit facility, December 31, 2004, PEC's common stock equity was even in the event of a MAC, Progress Energy may approximately 52.2% of total capitalization.

continue to borrow funds so long as the proceeds are used to repay maturing commercial paper balances. PEF's mortgage indenture provides that it will not pay any cash dividends upon its common stock, or make any CROSS-DEFAULT PROVISIONS other distribution to the stockholders, except a payment Each of these credit agreements contains cross-default or distribution out of net income of PEF subsequent to provisions for defaults of indebtedness in excess of December 31, 1943. At December 31, 2004, none of PEFs S10 million. Under these provisions, if the applicable retained earnings was restricted.

borrower or certain subsidiaries of the borrower fail to pay various debt obligations in excess of $10 million, the In addition, PEFs Articles of Incorporation provide that no lenders could accelerate payment of any outstanding cash dividends or distributions on common stock shall be borrowing and terminate their commitments to the credit paid, if the aggregate amountthereof since April 30,1944, facility. Progress Energy's cross-default provision applies including the amount then proposed to be expended, plus only to Progress Energy and its significant subsidiaries all other charges to retained earnings since April 30,1944, (i.e., PEC, Florida Progress, PEF, Progress Capital exceed (a)all credits to retained earnings since April 30, Holdings, Inc. (PCH) and Progress Fuels). 1944, plus (b)all amounts credited to capital surplus after April 30,1944, arising from the donation to PEF of cash or Additionally, certain of Progress Energy's long-term debt securities or transfers of amounts from retained earnings indentures contain cross-default provisions for defaults of to capital surplus.

indebtedness in excess of $25 million; these provisions apply onlyto other obligations of Progress Energy, primarily PEF's Articles of Incorporation also provide that cash dividends on common stock shall be limited to 75% of net commercial paper issued by the holding company, not its income available for dividends if common stock equity falls subsidiaries. In the event that these indenture cross-below 25% of total capitalization, and to 50% if common default provisions are triggered, the debt holders could accelerate payment of approximately $4.3 billion in long- stock equity falls below 20%. On December 31, 2004, term debt Certain agreements underlying the Companys PEF's common stock equity was approximately 54.4% of indebtedness also limit its ability to incur additional liens or total capitalization.

engage in certain types of sale and leaseback transactions.

C. Collateralized Obligations OTHER RESTRICTIONS PEC's and PEF's first mortgage bonds are collateralized Neither Progress Energy's Articles of Incorporation nor by their respective mortgage indentures. Each mortgage any of its debt obligations contain any restrictions on the constitutes a first lien on substantially all of the fixed payment of dividends. Certain documents restrict the properties of the respective company, subject to certain payment of dividends by Progress Energy's subsidiaries permitted encumbrances and exceptions. Each as outlined below. mortgage also constitutes a lien on subsequently acquired property. At December 31, 2004, PEC and PEF PEC's mortgage indenture provides that, as long as any had a total of approximately$3.84 billion of first mortgage first mortgage bonds are outstanding, cash dividends and bonds outstanding, including those related to pollution distributions on its common stock and purchases of its control obligations. Each mortgage allows the issuance common stock are restricted to aggregate net income of additional mortgage bonds upon the satisfaction of available for PEC since December 31, 1948, plus certain conditions.

S3 million, less the amount of all preferred stock dividends and distributions, and all common stock purchases, since D. Progress Genco Ventures, LLC December 31, 1948. At December 31, 2004, none of PEC's (Genco) Bank Facility retained earnings was restricted. In December 2004, Genco repaid its bank facility and recorded a $9 million pre-tax loss ($6 million after-tax) in In addition, PEC's Articles of Incorporation provide that other, net on the extinguishment At that time, the related cash dividends on common stock shall be limited to $195 million notional amount of interest rate collars in 75% of net income available for dividends if common place to hedge floating interest rate exposure on the bank stock equity falls below 25% of total capitalization, and facility was terminated and pre-tax deferred losses of to 50% if common stock equity falls below 20%. At $6 million ($4 million after-tax) were reclassified into 85

V Notes to Consolidated Financial Statements earnings in other, net due to the discontinuance of the decommissioning trust funds are presented on the hedges. The facility was obtained to be used exclusively Consolidated Balance Sheets at amounts that for expansion of its nonregulated generation portfolio. approximate fair value. Fair value is obtained from quoted Borrowings under this facility were secured by the assets market prices for the same or similar investments.

in the generation portfolio. The facility was for up to

$260 million, of which $241 million had been drawn at 15. INCOME TAXES December 31, 2003. Borrowings under the facility were Deferred income taxes have been provided for temporary restricted for the operations, construction, repayments differences. These occur when there are differences and other related charges of the credit facility for the between book and tax carrying amounts of assets and development projects. Cash held and restricted to liabilities. Investment tax credits related to regulated operations was S24 million at December 31,2003, and was operations have been deferred and are being amortized included in other current assets. Cash held and restricted over the estimated service life of the related properties. To for long-term purposes was S9 million at December 31, the extentthatthe establishment of deferred income taxes 2003, and was included in other assets and deferred debits under SFAS No. 109, 'Accounting for Income Taxes, (SFAS on the Consolidated Balance Sheets. No. 109) is different from the recovery of taxes by PEC and PEF through the ratemaking process, the differences are E. Guarantees of Subsidiary Debt deferred pursuant to SFAS No. 71. A regulatory asset or See Note 19 on related party transactions for a discussion liability has been recognized forthe impact of tax expenses of obligations guaranteed or secured by affiliates. or benefits that are recovered or refunded in different periods by the utilities pursuant to rate orders.

F. Hedging Activities Accumulated deferred income tax assets (liabilities) at Progress Energy uses interest rate derivatives to adjust December31 are:

the fixed and variable rate components of its debt portfolio and to hedge cash flow risk related to tin millions) 2004 2003 commercial paper and to fixed rate debt to be issued in Current deferred tax asset the future. See discussion of risk management activities Unbilled revenue $35 S18 and derivative transactions at Note 18. Other 86 69 Total current deferred tax asset 121 87

14. FAIR VALUE OF FINANCIAL INSTRUMENTS Noncurrent deferred tax asset (liability)

The carrying amounts of cash and cash equivalents and Investments 73 8 short-term obligations approximate fair value due to the Supplemental executive retirement plans 31 30 short maturities of these instruments. At December31,2004, Other post-employment benefits (OPEB) 126 119 and 2003, investments in company-owned life insurance Other pension plans (15) (97) and other benefit plan assets, with carrying amounts of Goodwill 34 46 approximately $220 million and $210 million, respectively, are included in miscellaneous other property and Accumulated depreciation and (1,374) (1,436) property cost differences investments in the Consolidated Balance Sheets and 26 Deferred costs (13) approximate fair value due to the short maturity of the Deferred storm costs (113) -

instruments. Other instruments, including short-term investments, are presented at fair value in accordance Deferred fuel (55) 31 with GAAP. The carrying amount of the Company's long- Federal income tax credit carry forward 779 683 term debt, including current maturities, was $9.870 billion State net operating loss carry forward 47 42 and S10.802 billion at December 31, 2004 and 2003, Valuation allowance (47) (42) respectively. The estimated fair value of this debt, as Miscellaneous othertemporarydifferences, net 43 (16) obtained from quoted market prices for the same or Total noncurrent deferred tax liabilities (484) (606) similar issues, was $10.843 billion and $11.917 billion at Less amount included in other assets December 31, 2004 and 2003, respectively. and deferred debits 10 9 Net noncurrent deferred tax liabilities $(494) $(615)

External trust funds have been established to fund certain costs of nuclear decommissioning (See Note 6D). Total deferred income tax liabilities were $2,797 million These nuclear decommissioning trust funds are invested and $2,662 million at December 31, 2004 and 2003, in stocks, bonds and cash equivalents. Nuclear respectively. Total deferred income tax assets were 86

Progress Energy Annual Report 2004

$2,434 million and $2,143 million at December 31,2004 and Reconciliations of the Company's effective income tax 2003, respectively. Total noncurrent income tax liabilities rate to the statutory federal income tax rate are:

on the Consolidated Balance Sheets at December 31,2004 2004 2003 2002 and 2003 include $105 million and $86 million, Effective income tax rate 13.5% (15.8)% (40.0)%

respectively, related to probable tax liabilities on which State income taxes, net of federal benefit (6.9) 13.3) (8.2) the Company accrues interestthatwould be payable with the related tax amount in future years. AFUDC amortization (0.5) (1.4) (5.2)

Federal tax credits 25.6 50.4 78.0 The federal income tax credit carry forward at Investmenttaxcreditamortization 1.6 2.3 4.7 December31, 2004, consists of $749 million of alternative ESOP dividend deduction 1.8 2.1 3.8 minimum tax credit with an indefinite carry forward Otherdifferences, net (0.1) 0.7 1.9 period and $30 million of general business credit with a Statutory federal income tax rate 35.0% 35.0% 35.0%

carry forward period that will begin to expire in 2020.

Income tax expense (benefit) applicable to continuing As of December 31, 2004, the Company had a state net operations is comprised of:

operating loss carry forward of $79 million, which will [in millions) 2004 2003 2002 begin to expire in 2007.

Current- federal S127 $127 S195 The Company established additional valuation allowances state 76 54 67 of $5million during 2004 and 2003 and S12 million during Deferred - federal (84) (255) (379) 2002, due to the uncertainty of realizing certain future state state 10 (21) (23) tax benefits. The Company believes it is more likely than Investmenttax credit (14) (16) (18) not that the results of future operations will generate Total income tax expense (benefit) S115 S0 1l) 5(158) sufficient taxable income to allow for the utilization of the remaining deferred tax assets. Progress Energy The company has recognized tax benefits from state net decreased its 2004 beginning of the year valuation operating loss carry forwards in the amount of $7million allowance by $8 million for a change in circumstances during 2004 and $3million during 2003 and 2002.

related to net operating losses.

The Company, through its subsidiaries, is a majority The Company establishes accruals for certain tax owner in five entities and a minority owner in one entity contingencies when, despite the belief that the that owns facilities that produce synthetic fuel as defined Company's tax return positions are fully supported, the under the Internal Revenue Code (Code). The production Company believes that certain positions may be and sale of the synthetic fuel from these facilities challenged and that it is probable the Company's qualifies for tax credits under Section 29 if certain positions may not be fully sustained. The Company is requirements are satisfied (See Note 23E).

under continuous examination by the Internal Revenue Service and other tax authorities and accounts for 16. CONTINGENT VALUE OBLIGATIONS potential losses of tax benefits in accordance with SFAS In connection with the acquisition of FPC during 2000, the No. 5. At December 31, 2004 and 2003, respectively, the Company issued 98.6 million contingent value obligations Company had recorded $60 million and $56 million of tax (CVOs). Each CVO represents the right to receive contingency reserves, excluding accrued interest and contingent payments based on the performance of four penalties, which are included in other current liabilities synthetic fuel facilities purchased by subsidiaries of FPC on the Consolidated Balance Sheets. Considering all tax in October 1999.The payments, if any, would be based on contingency reserves, the Company does not expect the the net after-tax cash flows the facilities generate. The resolution of these matters to have a material impact on CVO liability is adjusted to reflect market price its financial position or result of operations. All tax fluctuations. The unrealized loss/gain recognized due to contingency reserves relate to capitalization and basis these market fluctuations is recorded in other, net on the issues and do not relate to any potential disallowances of Consolidated Statements of Income (See Note 21). The tax credits from synthetic fuel production (See Note 23E). liability, included in other liabilities and deferred credits, at December 31, 2004 and 2003, was $13 million and

$23 million, respectively.

87

V Notes to Consolidated Financial Statements

17. BENEFIT PLANS subsidiaries provide contributory other postretirement benefits (OPEB), including certain health care and life A. Postretirement Benefits insurance benefits, for retired employees who meet The Company and some of its subsidiaries have a specified criteria.The Company uses a measurement date noncontributory defined benefit retirement (pension) plan of December31 for its pension and OPEB plans.

for substantially all full-time employees.The Company also has supplementary defined benefit pension plans that The components of netperiodic benefitcostfortheyears provide benefits to higher-level employees. In addition to ended December 31 are:

pension benefits, the Company and some of its Pension Benefits Other Postretirement Benefits (inmillions] 2004 2003 2002 2004 2003 2002 Service cost S54 S52 S45 $12 $15 $13 Interest cost 110 108 106 31 33 32 Expected return on plan assets 1155) (144) (161) (5) (4) (5)

Amortization of actuarial (gain) loss 21 25 2 4 5 1 Other amortization, net - - - 1 4 4 Net periodic cost/(benefit) 30 41 (8) 43 53 45 Additional cost/(benefit) recognition (Note 17B) (16) (18) (7) 2 2 2 Net periodic cosl(benefit) recognized $14 S23 $115) $45 $55 S47 The net periodic cost for other postretirement benefits obligation or the market-related value of assets are decreased during 2004 due to the implementation of amortized over the average remaining service period of FASB Staff Position 106-2 (See Note 2). In addition to the active participants.

net periodic cost and benefit reflected above, in 2003 the Company recorded curtailment and settlement effects To determine the market-related value of assets, the related to the disposition of NCNG, which are reflected Company uses a five-year averaging method for a portion in income/lloss) from discontinued operations in the of its pension assets and fair value for the remaining Consolidated Statements of Income. These effects portion. The Company has historically used the five-year included a pension-related loss of $13 million and an averaging method. When the Company acquired Florida OPEB-related gain of $1million. Progress in 2000, it retained the Florida Progress historical use of fair value to determine market-related Prior service costs and benefits are amortized on a value for Florida Progress pension assets.

straight-line basis over the average remaining service period of active participants. Actuarial gains and losses Reconciliations of the changes in the plans' benefit in excess of 10% of the greater of the projected benefit obligations and the plans' funded status are:

88

Progress Energy Annual Report 2004 Pension Benefits Other Postretirement Benefits (inmillions) 2004 2003 2004 2003 Projected benefit obligation at January 1 $1,772 $1,694 $472 $514 Service cost 54 52 12 15 Interest cost 110 108 31 33 Disposition of NCNG - (39) - (13)

Benefit payments (98) (94) (23) 124)

Plan amendment 21 - - -

Actuarial loss (gain) 102 51 46 (53)

Obligation at December 31 1,961 1,772 538 472 Fairvalue of plan assets at December31 1.774 1,631 70 65 Funded status (187) (141) (468) (407)

Unrecognized transition obligation - - 10 25 Unrecognized prior service cost 24 4 6 7 Unrecognized net actuarial loss 530 505 94 40 Minimum pension liability adjustment (470) (23) - -

Prepaid (accrued) cost at December 31, net (Note 17B) S(103) $345 S(358) S(335)

The 2003 OPEB obligation information above has been pre-tax charge of $229 million to accumulated other restated due to the implementation of FASB Staff Position comprehensive loss, a component of common stock 106-2 ISee Note 2). equity. A minimum pension liability adjustment of

$23 million, related to the supplementary defined benefit The net accrued pension cost of $103 million at December pension plans, was recorded at December 31, 2003. This 31,2004, is recognized in the Consolidated Balance Sheets adjustment is offset by a corresponding pre-tax amount as prepaid pension cost of S42 million and accrued benefit in accumulated other comprehensive loss.

cost of $145 million, which is included in accrued pension and other benefits. The net prepaid pension cost of Reconciliations of the fair value of plan assets are:

$345 million at December 31, 2003, is recognized in the Other Consolidated Balance Sheets as prepaid pension cost of Postretirement

$462 million and accrued benefit cost of $117 million, which Pension Benefits Benefits is included in accrued pension and other benefits. The (inmillions) 2004 2003 2004 2003 defined benefit pension plans with accumulated benefit Fair value of plan assets January 1 $1,631 $1,364 $65 $52 obligations in excess of plan assets had projected benefit Actual return on plan assets 211 391 8 12 obligations totaling $1.72 billion and S125 million at Disposition of NCNG - (35)

December31,2004 and 2003, respectively.Those plans had Benefit payments (98) (94) (23) (24) accumulated benefit obligations totaling $1.71 billion and

$117 million at December 31, 2004 and 2003, respectively, Employer contributions 30 5 20 25

$1.57 billion of plan assets at December 31, 2004, and no Fair value of plan assets at December 31 $1,774 $1,631 $70 $65 plan assets at December 31, 2003. The total accumulated benefit obligation for pension plans was $1.90 billion and

$1.72 billion at December 31, 2004 and 2003, respectively. In the table above, substantially all employer The accrued OPEB cost is included in accrued pension contributions represent benefit payments made directly and other benefits inthe Consolidated Balance Sheets. from Company assets except for the 2004 pension amount. The remaining benefits payments were made A minimum pension liability adjustment of $470 million directly from plan assets. In 2004, the Company made a was recorded at December 31, 2004. This adjustment required contribution of approximately $24 million directly resulted in a charge of S24 million to intangible assets, a to pension plan assets. The OPEB benefit payments

$150 million charge to a pension-related regulatory represent the net Company cost after participant liability (See Note 17B), a $67 million charge to a contributions. Participant contributions represent regulatory asset pursuant to a recent FPSC order and a approximately 20% of gross benefit payments.

89

V Notes to Consolidated Financial Statements The asset allocation forthe Company's plans atthe end of 2004 and 2003 and the target allocation for the plans, by asset category, are as follows:

Pension Benefits Other Postretirement Benefits Target Percentage of Plan Target Percentage of Plan Allocations Assets at Year End Allocations Assets at Year End Asset Category 2005 2004 2003 2005 2004 2003 Equity - domestic 48% 47% 49% 34% 34% 35%

Equity- international 15% 21% 22% 11% 15% 16%

Debt-domestic 12% 9% 11% 37% 35% 37%

Debt-international 10% 11% 11% 7% 8% 7%

Other 15% 12% 7% 11% 8%/o 5%

Total 100% 100%0 100% 100% 100% 100%

The Company sets target allocations among asset The following weighted-average actuarial assumptions classes to provide broad diversification to protect against were used in the calculation of the year-end obligation:

large investment losses and excessive volatility, while Other recognizing the importance of offsetting the impacts of Pension Postretirement benefit cost escalation. In addition, the Company Benefits Benefits employs external investment managers who have (in millions) 2004 2003 2004 2003 complementary investment philosophies and Discount rate 5.90% 6.30% 5.9% 6.30%

approaches. Tactical shifts (plus or minus 5%) in asset Rate of increase in allocation from the target allocations are made based on future compensation the near-term view of the risk and return tradeoffs of the Bargaining 3.50% 3.50% - -

asset classes. Supplementary plans 5.25% 5.00% - -

Initial medical cost trend rate for In 2005, the Company expects to make no required pre-Medicare benefits - - 7.25% 7.25%

contributions directly to pension plan assets and Initial medical cost trend rate for

$1 million of discretionary contributions directly to the post-Medicare benefits - - 7.25% 7.25%

OPEB plan assets. The expected benefit payments for the Ultimate medical cost trend rate - - 5.00% 5.25%

pension benefit plan for 2005 through 2009 and in total for Year ultimate medical costtrend 2010-2014, in millions, are approximately $113,$110,$115, rate is achieved - - 2008 2009

$124, $131 and $794, respectively. The expected benefit payments for the OPEB plan for 2005 through 2009 and in The Company's primary defined benefit retirement plan total for 2010-2014, in millions, are approximately $32, $34, for nonbargaining employees is a 'cash balance'

$37, $39, $41 and S230, respectively. The expected benefit pension plan as defined in EITF Issue No. 03-4. Therefore, payments include benefit payments directly from plan effective December 31, 2003, the Company began to use assets and benefit payments directly from Company the traditional unit credit method for purposes of assets. The benefit payment amounts reflect the net cost measuring the benefit obligation of this plan. Under the to the Company after any participant contributions. The traditional unit credit' method, no assumptions are Company expects to begin receiving prescription drug- included about future changes in compensation, and the related federal subsidies in 2006 (See Note 2), and the accumulated benefit obligation and projected benefit expected subsidies for 2006 through 2009 and in total for obligation are the same.

2010-2014, in millions, are approximately $3,S3, $3,$4and

$24, respectively. The expected benefit payments above do not reflect the potential effects of a 2005 voluntary enhanced retirement program (See Note 24).

90

Progress Energy Annual Report 2004 The following weighted-average actuarial assumptions cost reflected in the table above has a corresponding were used in the calculation of the net periodic cost: regulatory liability (See Note 8A). Pursuant to its rate treatment, PEF recognized additional periodic pension Other Postretirement Pension Benefits Benefits credits and additional periodic OPEB costs, as indicated in the net periodic cost information above.

[in millions) 2004 2003 2002 2004 2003 2002 Discount rate 6.30% 6.60% 7.50% 6.30% 6.60% 7.50% 18. RISK MANAGEMENT ACTIVITIES AND Rate of increase in future compensation DERIVATIVES TRANSACTIONS Bargaining 3.50% 3.50% 3.50% - - - Under its risk management policy, the Company may use Nonbargaining - 4.00% 4.00% - - - a variety of instruments, including swaps, options and Supplementary plans 5.00% 4.00% 4.00% - - - forward contracts, to manage exposure to fluctuations in Expected long-term rate commodity prices and interest rates. Such instruments of return on plan assets 9.25% 9.25% 9.25% 8.50% 8.45% 8.20% contain credit risk if the counterparty fails to perform under the contract. The Company minimizes such risk by The expected long-term rates of return on plan assets performing credit reviews using, among other things, were determined by considering long-term historical publicly available credit ratings of such counterparties.

returns for the plans and long-term projected returns Potential nonperformance by counterparties is not based on the plans' target asset allocation. For all expected to have a material effect on the consolidated financial position or consolidated results of operations of pension plan assets and a substantial portion of OPEB plans assets, those benchmarks support an expected the Company.

long-term rate of return between 9.0% and 9.5%. The Company has chosen to use an expected long-term rate A. Commodity Derivatives of 9.25%. GENERAL Most of the Company's commodity contracts are not The medical cost trend rates were assumed to decrease derivatives pursuant to SFAS No. 133 or do not qualify as gradually from the initial rates to the ultimate rates.

normal purchases or sales pursuant to SFAS No. 133.

Assuming a 1%increase in the medical cost trend rates, Therefore, such contracts are not recorded at fair value.

the aggregate of the service and interest cost components of the net periodic OPEB cost for 2004 would During 2003 the FASB reconsidered an interpretation of increase by $1 million, and the OPEB obligation at SFAS No. 133 related to the pricing of contracts that December 31, 2004, would increase by $30 million. include broad market indices (e.g., CPI). Inparticular, that Assuming a 1%decrease in the medical cost trend rates, guidance discussed whether the pricing in a contract the aggregate of the service and interest cost that contains broad market indices could qualify as a components of the net periodic OPEB costfor 2004 would normal purchase or sale (the normal purchase or sale decrease by S1 million, and the OPEB obligation at term is a defined accounting term, and may not, in all December 31, 2004, would decrease by $26 million.

cases, indicate whether the contract would be 'normal' from an operating entity viewpoint). The FASB issued B. FPC Acquisition final superseding guidance (DIG Issue C20) on this issue During 2000, the Company completed the acquisition of effective October 1,2003,for the Company. DIG Issue C20 FPC. FPC's pension and OPEB liabilities, assets and net specifies new pricing-related criteria for qualifying as a periodic costs are reflected in the above information as normal purchase or sale, and it required a special appropriate. Certain of FPC's nonbargaining unit benefit transition adjustment as of October 1,2003.

plans were merged with those of the Company effective January 1,2002. PEC determined that it had one existing 'normal" contract that was affected by DIG Issue C20. Pursuant to PEF continues to recover qualified plan pension costs the provisions of DIG Issue C20, PEC recorded a pre-tax and OPEB costs in rates as if the acquisition had not fair value loss transition adjustment of $38 million occurred. Accordingly, a portion of the accrued OPEB ($23 million after-tax) in the fourth quarter of 2003, which cost reflected in the table above has a corresponding was reported as a cumulative effect of a change in regulatory asset at December 31, 2004, and 2003 (See accounting principle. The subject contract meets the DIG Note 8A). In addition, a portion of the prepaid pension Issue C20 criteria for normal purchase or sale and, 91

V Notes to Consolidated Financial Statements therefore, was designated as a normal purchase as of The ineffective portion of commodity cash flow hedges October 1, 2003. The original liability of $38 million was not material to the Company's results of operations associated with the fair value loss is being amortized to for 2004, 2003 or 2002. At December 31, 2004, there were earnings over the term of the related contract. At S9 million of after-tax deferred losses in accumulated December 31, 2004 and 2003, the remaining liability was other comprehensive income (OCI), of which $5million is

$26 million and $35 million, respectively. expected to be reclassified to earnings during the next 12 months as the hedged transactions occur. Gains and ECONOMIC DERIVATIVES losses are recorded net in operating revenues. As part of the divestiture of Winchester Production Company, Ltd.,

Derivative products, primarily electricity and natural gas assets in 2004, $7million of after-tax deferred losses were contracts, are entered into for economic hedging purposes. While management believes the economic reclassified into earnings due to discontinuance of the hedges mitigate exposures to fluctuations in commodity related cash flow hedges and recorded against the gain on sale. Due to the volatility of the commodities markets, prices, these instruments are not designated as hedges for accounting purposes and are monitored consistent the value in OCI is subject to change prior to its with trading positions. The Company manages open reclassification into earnings.

positions with strict policies that limit its exposure to market risk and require daily reporting to management of B. Interest Rate Derivatives -

potential financial exposures. Gains and losses from Fair Value or Cash Flow Hedges such contracts were not material to results of operations The Company uses cash flow hedging strategies to during 2004, 2003 or 2002, and the Company did not have hedge variable interest rates on long-term and short-material outstanding positions in such contracts at term debt and to hedge interest rates with regard to December 31, 2004 and 2003. future fixed-rate debt issuances. Gains and losses are recorded in OCI and amounts reclassified to earnings are In2004, PEF entered into derivative instruments related to included in net interest charges as the hedged its exposure to price fluctuations on fuel oil purchases. At transactions occur. The Company uses fairvalue hedging December 31, 2004, the fair values of these instruments strategies to manage its exposure to fixed interest rates were a $2 million long-term derivative asset position on long-term debt For interest rate fair value hedges, the included in other assets and deferred debits and a change in the fair value of the hedging derivative is

$5million short-term derivative liability position included recorded in net interest charges and is offset by the in other current liabilities. These instruments receive change in the fair value of the hedged item.

regulatory accounting treatment Gains are recorded in regulatory liabilities and losses are recorded in The fair values of open position interest rate hedges at regulatory assets. December 31, 2004 and 2003 were as follows:

CASH FLOW HEDGES (inmillions) 2004 2003 Interestrate cash flow hedges $12) $(6)

Progress Energy's subsidiaries designate a portion of Interest rate fair value hedges $3 $14) commodity derivative instruments as cash flow hedges under SFAS No. 133. The objective for holding these instruments is to hedge exposure to market risk CASH FLOW HEDGES associated with fluctuations in the price of natural gas for The following table presents selected information related the Company's forecasted purchases and sales. At to the Company's interest rate cash flow hedges included December 31, 2004, the maximum period over which the in accumulated OCI at December 31, 2004:

Company is hedging exposures to the price variability of Accumulated Other natural gas is 10 years. Comprehensive Income/(Loss), Portion Expected to be net of taxlal Reclassified to Earnings The total fair value of commodity cash flow hedges at (millions of dollars) during the Next 12 Monthslb)

December 31, 2004 and 2003 was as follows: S(19) S(4) ta) Includes amounts related to terminated hedges.

(millions of dollars) 2004 2003 (b Actual amounts that will be reclassified to earnings may vary from the Fair value of assets S- $- expected amounts presented above as a result of changes in interest rates.

Fair value of liabilities (15) (12)

Fairvalue, net 5(15) S(12) 92

Progress Energy Annual Report 2004 As of December 31, 2004, PEC had $110 million notional The notional amounts of interest rate derivatives are not amount of pay-fixed forward swaps to hedge its exchanged and do not represent exposure to credit loss.

exposure to interest rates with regard to future Inthe event of default by a counterparty, the risk in these issuances of debt (pre-issue hedges) and $21 million transactions is the cost of replacing the agreements at notional amount of pay-fixed forward starting swaps to current market rates.

hedge its exposure to interest rates with regard to an upcoming railcar lease. On February4,2005, PEC entered 19. RELATED PARTY TRANSACTIONS another $50 million notional amount of its pre-issue As a part of normal business, Progress Energy and hedges. All the swaps have a computational period of certain subsidiaries enter into various agreements 10 years. PEC held no interest rate cash flow hedges at providing financial or performance assurances to third December 31, 2003. The ineffective portion of interest parties. These agreements are entered into primarily to rate cash flow hedges was not material to the Company's support or enhance the creditworthiness otherwise results of operations for 2004 and 2003. attributed to a subsidiary on astand-alone basis, thereby facilitating the extension of sufficient credit to InDecember 2004, Progress Ventures, Inc. (PVI), a wholly accomplish the subsidiaries' intended commercial owned subsidiary of Progress Energy, terminated purposes. As of December 31,2004, Progress Energy and S195 million notional amount of interest rate collars in its subsidiaries' guarantees include: $270 million place to hedge floating interest rate exposure associated supporting commodity transactions, $181 million to with variable-rate long-term debt. The related debt was support nuclear decommissioning, $536 million related to also extinguished in December 2004 (See Note 13). Pre- power supply agreements and $182 million for tax deferred losses of $6million ($4 million after-tax) were guarantees supporting other agreements of subsidiaries.

reclassified into earnings in other, net due to Progress Energy also purchased $92 million of surety discontinuance of these cash flow hedges. bonds and authorized the issuance of standby letters of credit by financial institutions of $50 million. Florida At December 31, 2004 and 2003, Progress Energy, Inc., Progress also fully guarantees the medium-term notes held interest rate cash flow hedges, with a total notional outstanding for Progress Capital, a wholly owned amount of $200 million and $400 million, respectively, subsidiary of Florida Progress (See Note 13). At related to projected outstanding balances of commercial December 31, 2004, management does not believe paper. The fair value of the hedges at December 31, 2004, conditions are likely for significant performance under was not material to the Company's financial condition and these agreements. To the extent liabilities are incurred at December 31, 2003, was S5 million. The hedges held at as a result of the activities covered by the guarantees, December 31, 2003, were terminated during the year. such liabilities are included in the Balance Sheets.

Amounts in accumulated other comprehensive income related to these terminated hedges will be reclassified to Progress Fuels sells coal to PEF for an insignificant earnings as the hedged interest payments occur. profit. These intercompany revenues and expenses are eliminated in consolidation; however, in accordance FAIR VALUE HEDGES with SFAS No. 71, profits on intercompany sales to As of December 31, 2004 and 2003, Progress Energy had regulated affiliates are not eliminated if the sales price is S150 million notional amount and $850 million notional reasonable and the future recovery of sales price amount, respectively, of fixed rate debt swapped to floating through the ratemaking process is probable. Sales, net rate debt by executing interest rate derivative agreements. of insignificant profits, of $331 million, $346 million and These agreements expire on various dates through March $329 million for the years ended December 31, 2004, 2011. During 2004, Progress Energy entered into 2003 and 2002, respectively, are included in fuel used S350 million notional amount and terminated $1.05 billion in electric generation on the Consolidated Statements notional amount of interest rate swap agreements. of Income.

At December 31, 2004 and 2003, the Company had Florida Progress Funding Corporation's (Funding Corp.)

S9 million and $23 million, respectively, of basis adjustments $309 million 7.10% Junior Subordinated Deferrable in long-term debt related to terminated interest rate fair Interest Notes (Subordinated Notes) are due to FPC value hedges, which are being amortized over periods Capital I (the Trust). The Trust was established for the ending in 2006 through 2011 coinciding with the maturities sole purpose of issuing $300 million Preferred Securities of the related debt instruments. and using the proceeds thereof to purchase from Funding Corp. its Subordinated Notes due 2039. The 93

V Notes to Consolidated Financial Statements Company has fully and unconditionally guaranteed the the FPSC. These electric operations also distribute and obligations of Funding Corp. under the Subordinated sell electricity to other utilities, primarily on the east Notes (the Notes Guarantee). In addition, the Company coast of the United States.

has guaranteed the payment of all distributions related to the $300 million Preferred Securities required to be Fuels operations, which are located throughout the made by the Trust, but only to the extent that the Trust United States, are involved in natural gas drilling and has funds available for such distributions (Preferred production, coal terminal services, coal mining, synthetic Securities Guarantee). The Preferred Securities fuel production and fuel transportation and delivery.

Guarantee, considered together with the Notes Guarantee, constitutes a full and unconditional CCO's operations, which are located in the southeastern guarantee by the Company of the Trust's obligations United States, include nonregulated electric generation under the Preferred Securities. The Subordinated Notes operations and marketing activities.

and the Notes Guarantee are the sole assets of the Trust The Subordinated Notes may be redeemed at the option Rail Services' operations include railcar repair, rail parts of Funding Corp. at par value plus accrued interest reconditioning and sales, railcar leasing and sales and through the redemption date. The proceeds of any scrap metal recycling. These activities include redemption of the Subordinated Notes will be used by maintenance and reconditioning of salvageable scrap the Trust to redeem proportional amounts of the components of railcars, locomotive repair and right-of-Preferred Securities and common securities in way maintenance. Rail Services' operations are located accordance with their terms. Upon liquidation or in the United States, Canada and Mexico.

dissolution of Funding Corp., holders of the Preferred Securities would be entitled to the liquidation preference In addition to these reportable operating segments, the of $25 per share plus all accrued and unpaid dividends Company has Corporate and Other activities that include thereon to the date of payment. The yearly interest holding company and service company operations as well expense is $21 million and is reflected in the as other nonregulated business areas. These nonregulated Consolidated Statements of Income. business areas include telecommunications and energy service operations and other nonregulated subsidiaries that The Company sold NCNG to Piedmont Natural Gas do notseparatelymeetthe disclosure requirements of SFAS Company, Inc. on September 30, 2003 (See Note 4E). No. 131, 'Disclosures about Segments of an Enterprise and Prior to disposition, NCNG sold natural gas to affiliates. Related Information." Included in the 2004 losses is a During the years ended December 31, 2003 and 2002, $43 million pre-tax ($29 million after-tax) settlement sales of natural gas to affiliates amounted to $11 million agreementthat SRS reached with the San Francisco United and $20 million, respectively. These revenues are School District related to civil proceedings. Included in the included in discontinued operations on the Consolidated 2002 losses are asset impairments and certain other after-Statements of Income. tax charges related to the telecommunications operations of $225 million. The operations of NCNG were reclassified to

20. FINANCIAL INFORMATION discontinued operations and therefore are not included in BY BUSINESS SEGMENT the results from continuing operations during the periods reported. The profit or loss of the identified segments plus The Company currently provides services through the the loss of Corporate and Other represents the Company's following business segments: PEC Electric, PEF, Fuels, total income from continuing operations.

CCO and Rail Services. Prior to 2004, other nonregulated business activities were reported separately in the Products and services are sold between the various Other segment. These reportable segment changes reportable segments. All intersegment transactions are reflect the current reporting structure. For comparative at cost except for transactions between Fuels and PEF, purposes, the results have been restated to align with which are at rates set by the FPSC. In accordance with the current presentation. SFAS No. 71, profits on intercompany sales between PEF and Fuels are not eliminated if the sales price is PEC Electric and PEF are primarily engaged in the reasonable and the future recovery of sales price generation, transmission, distribution and sale of electric through the ratemaking process is probable. The profits energy in portions of North Carolina, South Carolina and for all three years presented were not significant.

Florida. These electric operations are subject to the rules and regulations of the FERC, the NCUC, the SCPSC and 94

Progress Energy Annual Report 2004 PEC Rail Corporate (inmillions) Electric PEF Fuels CCO Services and Other Eliminations Totals Year ended December 31, 2004 Revenues Unaffiliated $3,528 $3,525 $1,179 $240 $1.130 $70 S- $9.772 Intersegment - - 331 - 1 441 (773) -

Total revenues 3,628 3,525 1,510 240 1,131 511 (773) 9,772 Depreciation and amortization 570 281 93 58 21 45 - 1,068 Total interest charges, net 192 114 22 17 27 361 (86) 647 Gain on sale of assets - - 54 - - 3 - 57 Income tax expense (benefit)(a) 237 174 (230) (1) 15 (80) - 115 Segment profit (loss) 464 333 180 (4) 16 (236) - 753 Total assets 10.590 7,924 986 1.709 596 17,741 (13,553) 25.993 Capital and investment expenditures 519 480 157 25 40 14 - 1,235 Year ended December31,2003 Revenues Unaffiliated $3,589 $3,152 S928 S170 $846 S56 S- $8,741 Intersegment - - 346 - 1 446 (793) -

Total revenues 3,589 3,152 1,274 170 847 502 (793) 8,741 Depreciation and amortization 562 307 80 42 20 29 - 1,040 Total interest charges, net 197 91 23 4 29 356 (72) 628 Impairment of long-lived assets and investments 11 - 17 - - 10 - 38 Income tax expense (benefit)(3) 238 147 (415) 8 2 (46) (45) (111)

Segmentprofit(loss) 515 295 235 20 (1) (253) - 811 Total assets 10,748 7,280 1,142 1,747 586 17,955 (13,365) 26,093 Capital and investment expenditures 445 526 309 338 103 35 - 1,756 Year ended December 31, 2002 Revenues Unaffiliated $3,539 S3,062 $607 $92 $714 $77 S- $8,091 Intersegment - - 329 - 5 418 (752) -

Total revenues 3,539 3,062 936 92 719 495 (752) 8,091 Depreciation and amortization 524 295 47 20 20 32 - 938 Totalinterestchargesnet 212 106 24 (12) 33 351 (81) 633 Impairment of long-lived assets and investments - - - - 59 330 - 389 Incometaxexpense(beneft)(a) 237 163 (373) 16 (16) (191) 6 (158)

Segment profit (loss) 513 323 176 27 (42) (445) - 552 Total assets 10,139 6,678 934 1,452 529 15,872 111,886) 23,718 Capital and investment expenditures 619 550 170 682 8 73 - 2,102 (a)Amounts include income tax benefit reallocation from holding company to profitable subsidiaries according to an SEC order.

95

V Notes to Consolidated Financial Statements Geographic Data 22. ENVIRONMENTAL MATTERS (inmillions) U.S. Canada Mexico Consolidated The Company is subject to federal, state and local 2004 regulations addressing hazardous and solid waste Consolidated revenues $9,644 $112 $16 S9.772 management, air and water quality and other 2003 environmental matters.

Consolidated revenues $8,624 S103 $14 S8,741 Hazardous and Solid Waste Management 2002 Consolidated revenues $7,984 S93 $14 $8,091 The provisions of the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), authorize the EPA to require the

21. OTHER INCOME AND OTHER EXPENSE cleanup of hazardous waste sites. This statute imposes Other income and expense includes interest income, retroactive joint and several liabilities. Some states, impairment of investments and other income and including North and South Carolina, have similar types of expense items as discussed below. The components of legislation. The Company and its subsidiaries are other, net as shown on the Consolidated Statements of periodically notified by regulators including the EPA and Income for the years ended December31 are as follows: various state agencies of their involvement or potential (inmillions) 2004 2003 2002 involvement in sites that may require investigation and/or remediation. There are presently several sites with Other Income respect to which the Company has been notified by the Nonregulated energy and delivery services income $32 $27 $33 EPA, the State of North Carolina or the State of Florida of DIG Issue C20 amortization (Note 18A) 9 2 -

its potential liability, as described below in greater detail.

Contingent value obligation The Company also is currently in the process of unrealized gain (Note 16) 9 - 28 assessing potential costs and exposures at other sites.

Investment gains - 5 - For all sites, as assessments are developed and AFUDC equity 11 14 8 analyzed, the Company will accrue costs for the sites to Gain on sale of property and the extent the costs are probable and can be reasonably partnership investments 12 25 12 estimated. A discussion of sites by legal entity follows.

Other 34 17 42 Total other income S107 $90 $123 Various organic materials associated with the production of manufactured gas, generally referred to as coal tar, Other Expense are regulated under federal and state laws. PEC and PEF Nonregulated energy and delivery services expenses $20 $20 S29 are each potentially responsible parties (PRPs) at several manufactured gas plant (MGP) sites.

Donations 10 12 19 Investment losses 6 - -

PEC, PEF and Progress Fuels Corporation have filed Contingent value obligation unrealized loss (Note 16) - 9 -

claims with the Company's general liability insurance carriers to recover costs arising from actual or potential Loss from equity investments 6 40 21 environmental liabilities. Some claims have been settled Loss on debt extinguishment and interest rate collars (Note 13D) 15 - -

and others are still pending. While the Company cannot predict the outcome of these matters, the outcome is not Other 42 25 27 expected to have a material effect on the consolidated Total other expense $99 $106 $96 financial position or results of operations.

Other, net $8 S(16) $27 PEC Nonregulated energy and delivery services include There are nine former MGP sites and a numberof othersites power protection services and mass market programs associated with PEC that have required or are anticipated (surge protection, appliance services and area light to require investigation and/or remediation costs.

sales) and delivery, transmission and substation work for other utilities. During the fourth quarter of 2004, the EPA advised PEC that it had been identified as a PRP at the Ward Transformer site located in Raleigh, North Carolina. The EPA offered PEC and 34 other PRPs the opportunity to 96

Progress Energy Annual Report 2004 negotiate cleanup of the site and reimbursement of less environmental sites, which are included in other liabilities than $2 million to the EPA for EPA's past expenditures in and deferred credits and are expected to be paid out over addressing conditions at the site. Although a loss is many years, were:

considered probable, an agreement among PRPs has not (inmillions) 2004 2003 been reached; consequently, it is not possible at this time to reasonably estimate the total amount of PEC's Remediation of distribution and substation transformers $27 $12 obligation for remediation of the Ward Transformer site. MGP and other sites 18 6 Total accrual for environmental sites $45 $18 At December 31, 2004, and 2003, PEC's accruals for probable and estimable costs related to various PEF has received approval from the FPSC for recovery of environmental sites, which are included in other liabilities costs associated with the remediation of distribution and and deferred credits and are expected to be paid out over substation transformers through the Environmental Cost many years, were: Recovery Clause (ECRC). Under agreements with the Florida Department of Environmental Protection (FDEP),

(inmillions) 2004 2003 PEF is in the process of examining distribution Insurance fund $7 $9 transformer sites and substation sites for potential Transferred from NCNG attime of sale 2 2 equipment integrity issues that could result in the need Total accrual for environmental sites $9 S11 for mineral oil impacted soil remediation. Through 2004 PEF has reviewed a number of distribution transformer PEC received insurance proceeds to address costs sites and substation sites. PEF expects to have associated with environmental liabilities related to its completed its review of distribution transformer sites by involvement with some sites. All eligible expenses the end of 2007 and has completed the review of related to these are charged against a specific fund substation sites in 2004. Should further sites be identified, containing these proceeds. PEC spent approximately PEF believes that any estimated costs would also be

$2 million related to environmental remediation in 2004. recovered through the ECRC clause. In2004, PEF accrued PEC is unable to provide an estimate of the reasonably an additional $19 million due to identification of additional possible total remediation costs beyond what iscurrently sites requiring remediation, and spent approximately accrued because investigations have not been $4million related to the remediation of transformers. PEF completed at all sites. has recorded a regulatory asset for the probable recovery of these costs through the ECRC.

This accrual has been recorded on an undiscounted basis. PEC measures its liability for these sites based on The amounts for MGP and other sites, in the table above, available evidence including its experience in relate to two former MGP sites and other sites investigating and remediating environmentally impaired associated with PEF that have required or are sites. The process often involves assessing and anticipated to require investigation and/or remediation.

developing cost-sharing arrangements with other PRPs. In 2004, PEF received approximately $12 million in PEC will accrue costs for the sites to the extent its liability insurance claim settlement proceeds and recorded a is probable and the costs can be reasonably estimated. related accrual for associated environmental expenses.

Because the extent of environmental impact, allocation The proceeds are restricted for use in addressing costs among PRPs for all sites, remediation alternatives (which associated with environmental liabilities. Expenditures could involve either minimal or significant efforts), and for the year were less than $1million.

concurrence of the regulatory authorities have not yet reached the stage where a reasonable estimate of the These accruals have been recorded on an undiscounted remediation costs can be made, PEC cannot determine basis. PEF measures its liability for these sites based on the total costs that may be incurred in connection with available evidence including its experience in the remediation of all sites at this time. It is anticipated investigating and remediating environmentally impaired that sufficient information will become available for sites. This process often includes assessing and several sites during 2005 to allow a reasonable estimate developing cost-sharing arrangements with other PRPs.

of PEC's obligation for those sites to be made. Because the extent of environmental impact, allocation among PRPs for all sites, remediation alternatives (which PEF could involve either minimal or significant efforts), and concurrence of the regulatory authorities have not yet At December 31, 2004, and 2003, PEF's accruals for advanced to the stage where a reasonable estimate of probable and estimable costs related to various 97

V Notes to Consolidated Financial Statements the remediation costs can be made, at this time PEF is Air Quality unable to provide an estimate of its obligation to remediate these sites beyond what is currently accrued. Congress is considering legislation that would require As more activity occurs atthese sites, PEFAwill assessthe reductions in air emissions of NOx, S02, carbon dioxide need to adjust the accruals. It is anticipated that and mercury. Some of these proposals establish sufficient information will become available in 2005 to nationwide caps and emission rates over an extended make a reasonable estimate of PEFs obligation for one of period of time. This national multi-pollutant approach to the MGP sites. air pollution control could involve significant capital costs that could be material to the Company's consolidated The Florida Legislature passed risk-based corrective financial position or results of operations. Control action (RBCA, known as Global RBCA) legislation in the equipment that will be installed on North Carolina fossil 2003 regular session. Risk-based corrective action generating facilities as part of the NC Clean Air generally means that the corrective action prescribed legislation discussed below may address some of the for contaminated sites can correlate to the level of issues outlined above. However, the Company cannot human health risk imposed by the contamination at the predict the outcome of this matter.

property. The Global RBCA law expands the use of the risk-based corrective action to all contaminated sites in The EPA is conducting an enforcement initiative related the state that are not currently in one of the state's waste to a number of coal-fired utility power plants in an effort cleanup programs. The FDEP developed the rules to determine whether changes at those facilities were required by the RBCA statute, holding meetings with subject to New Source Review requirements or New interested stakeholders and hosting public workshops. Source Performance Standards under the Clean Air Act.

The rules have the potential for making future cleanups The Company was asked to provide information to the in Florida more costly to complete. The Global RBCA rule EPA as part of this initiative and cooperated insupplying was adopted at the February 2, 2005, Environmental the requested information. The EPA initiated civil Review Commission hearing. The effective date of the enforcement actions against other unaffiliated utilities as Global RBCA rule is expected to be announced in April part of this initiative. Some of these actions resulted in 2005. The Company and PEF are in the process of settlement agreements calling for expenditures by these assessing the impact of this matter. unaffiliated utilities, in excess of $1.0 billion. These settlement agreements have generally called for Florida Progress Corporation expenditures to be made over extended time periods, and some of the companies may seek recovery of the related In 2001, FPC established a $10 million accrual to address cost through rate adjustments or similar mechanisms.

indemnities and retained an environmental liability The Company cannot predict the outcome of this matter.

associated with the sale of its Inland Marine Transportation business. In 2003, the accrual was In2003, the EPA published afinal rule addressing routine reduced to $4 million based on a change in estimate. equipment replacement under the New Source Review During 2004, expenditures related to this liability were not program. The rule defines routine equipment material to the Company's financial condition. As of replacement and the types of activities that are not December 31, 2004, the remaining accrual balance was subject to New Source Review requirements or New approximately $3 million. FPC measures its liability for Source Performance Standards under the Clean Air Act.

these exposures based on estimable and probable The rule was challenged in the Federal Appeals Court remediation scenarios. and its implementation stayed. In July 2004, the EPA announced it will reconsider certain issues arising from Certain historical sites are being addressed voluntarily by the final routine equipment replacement rule. The FPC. An immaterial accrual has been established to comment period closed on August30,2004.The Company address investigation expenses related to these sites. At cannot predict the outcome of this matter.

this time, the Company cannot determine the total costs that may be incurred in connection with these sites. In 1998, the EPA published afinal rule under Section 110 of the Clean Air Act addressing the regional transport of Rail ozone (NOx SIP Call). Total capital expenditures to meet Rail Services is voluntarily addressing certain historical the requirements of the NOx SIP Call Rule in North and waste sites. At this time, the Company cannot determine South Carolina could reach approximately $370 million, the total costs that may be incurred in connection with which has not been adjusted for inflation. To date, the these sites. Company has spent approximately $282 million related to 98

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V Notes to Consolidated Financial Statements InDecember 2003, the EPA released its proposed Interstate $115 million. The range includes $20 million to $30 million at Air Quality Rule, currently referred to as the Clean Air PEC and $65 million to $85 million at PEF Interstate Rule (CAIR).The final rule was released on March 10, 2005. The EPA's rule requires 28 states and the District of Other Environmental Matters Columbia, including North Carolina, South Carolina, Georgia and Florida, to reduce NOx and S02 emissions in order to The Kyoto Protocol was adopted in 1997 by the United attain preset state NOx and S02 emissions levels. The Nations to address global climate change by reducing Company is reviewing the final rule. Installation of additional emissions of carbon dioxide and other greenhouse air quality controls is likely to be needed to meet the CAIR gases. In 2004, Russia ratified the Protocol, and the treaty requirements. Compliance plans and cost to comply with went into effect on February 16, 2005. The United States the rule will be determined once the Company completes Rts has not adopted the Kyoto Protocol, and the Bush review. The air quality controls already installed for administration has stated it favors voluntary programs. A compliance with the NOx SIP Call and currently planned by number of carbon dioxide emissions control proposals the Companyto complywith the NC Clean Air legislation will have been advanced in Congress. Reductions in carbon reduce the costs required to meet the CAIR requirements dioxide emissions to the levels specified by the Kyoto for the Company's North Carolina units. Protocol and some legislative proposals could be materially adverse to the Company's consolidated In March 2004, the North Carolina Attorney General filed financial position or results of operations if associated a petition with the EPA under Section 126 of the Clean Air costs of control or limitation cannot be recovered from Act, asking the federal government to force coal-fired customers. The Company favors the voluntary program power plants in 13 other states, including South Carolina, approach recommended by the administration and to reduce their NOx and S02 emissions. The state of continually evaluates options for the reduction, North Carolina contends these out-of-state emissions avoidance and sequestration of greenhouse gases.

interfere with North Carolina's ability to meet national air However, the Company cannot predict the outcome of quality standards for ozone and particulate matter. The this matter.

EPA has agreed to make a determination on the petition by August 1, 2005. The Company cannot predict the Progress Energy has announced its plan to issue a report outcome of this matter. on the Company's activities associated with current and future environmental requirements. The report will Water Quality include a discussion of the environmental requirements that the Company currently faces and expects to face in As a result of the operation of certain control equipment the future, as well as an assessment of potential needed to address the air quality issues outlined above, mandatory constraints on carbon dioxide emissions. The new wastewater streams may be generated at the report will be issued by March 31, 2006.

affected facilities. Integration of these new wastewater streams into the existing wastewater treatment 23. COMMITMENTS AND CONTINGENCIES processes may result in permitting, construction and treatment requirements imposed on PEC and PEF in the A. Purchase Obligations immediate and extended future. At December 31, 2004, the following table reflects Progress Energy's contractual cash obligations and other After many years of litigation and settlement negotiations, commercial commitments in the respective periods in the EPA adopted regulations in February 2004to implement which they are due:

Section 316(b) of the Clean Water Act. These regulations became effective September 7,2004.The purpose of these (inmillions) 2005 2006 2007 2008 2009 Thereafter regulations is to minimize adverse environmental impacts Fuel S2,219 $1,473 $663 $229 $252 $1,270 caused by cooling water intake structures and intake Purchased power 473 473 479 449 416 4,614 systems. Overthe next several years these regulations will Construction impact the larger base load generation facilities and may obligations 51 - - - - -

require the facilities to mitigate the effects to aquatic Other purchase organisms by constructing intake modifications or obligations 100 70 64 41 39 268 undertaking other restorative activities. The Company Total S2,843 $2,016 S1,206 S719 $707 S6,152 currently estimates that from 2005 through 2009 the range of its expenditures to meet the Section 316(b) requirements of the Clean Water Act will be $85 million to 100

Progress Energy Annual Report 2004 FUEL AND PURCHASED POWER additional purchase of approximately 300 MW of capacity through 2022 with an original minimum annual FPC, PEC and Fuels have entered into various long-term payment of approximately $16 million representing contracts for coal, oil and gas. Payments under these capital-related capacity costs. Total purchases for both commitments were S2,097 million, $1,719 million and capacity and energy under the Broad River agreements S1,414 million for 2004, 2003 and 2002, respectively. amounted to $42 million, $37 million and $38 million in 2004, 2003 and 2002 respectively.

Pursuant to the terms of the 1981 Power Coordination Agreement, as amended, between PEC and the North PEF has long-term contracts for approximately 489 MW of Carolina Eastern Municipal Power Agency (Power purchased power with other utilities, including a contract Agency), PEC is obligated to purchase a percentage of with The Southern Company for approximately 414 MW of Power Agency's ownership capacity of, and energy from, purchased power annually through 2015. Total purchases, the Harris Plant In 1993, PEC and Power Agency entered for both energy and capacity, under these agreements into an agreement to restructure portions of their amounted to $129 million, $124 million and $109 million for contracts covering power supplies and interests in jointly 2004,2003 and 2002, respectively. Total capacity payments owned units. Under the terms of the 1993 agreement, PEC were $56 million, $55 million and $50 million for 2004, 2003 increased the amount of capacity and energy purchased and 2002, respectively. Minimum purchases under these from Power Agency's ownership interest in the Harris contracts, representing capital-related capacity costs, at Plant, and the buyback period was extended six years December 31, 2004, are $60 million, $63 million, $65 million, through 2007.The estimated minimum annual payments for

$66 million and $67 million for 2005 through 2009, these purchases, which reflect capacity and energy costs, respectively, and $244 million thereafter.

total approximately $38 million. These contractual purchases totaled $39 million, $36 million and $36 million Both PEC and PEF have ongoing purchased power for 2004, 2003 and 2002, respectively. In 1987, the NCUC contracts with certain cogenerators (qualifying facilities) ordered PECto reflectthe recovery of the capacity portion with expiration dates ranging from 2005 to 2025. These of these costs on a levelized basis overthe original 15-year purchased power contracts generally provide for buyback period, thereby deferring for future recovery the capacity and energy payments. Energy payments for the difference between such costs and amounts collected PEF contracts are based on actual power taken under through rates. In 1988, the SCPSC ordered similar these contracts. Capacity payments are subject to the treatment, but with a 10-year levelization period. At qualifying facilities (QFs) meeting certain contract December 31, 2004, all previously deferred costs have performance obligations. PEF's total capacity purchases been expensed.

under these contracts amounted to $248 million,

$244 million and $235 million for 2004, 2003 and 2002, PEC has a long-term agreementforthe purchase of power respectively. Minimum expected future capacity and related transmission services from Indiana Michigan payments under these contracts at December 31, 2004, Power Company's Rockport Unit No. 2 (Rockport). The are $271 million, $279 million, $289 million, $298 million and agreement provides for the purchase of 250 MW of

$263 million for 2005 through 2009, respectively, and capacity through 2009 with estimated minimum annual

$3.8 billion thereafter. PEC has various pay-for-payments of approximately $43 million, representing performance contracts with QFs for approximately capital-related capacity costs. Estimated annual payments 400 MW of capacity expiring at various times through for energy and capacity costs are approximately 2009. Payments for both capacity and energy are S72 million through 2009. Total purchases (including energy contingent upon the QFs' ability to generate. Payments and transmission use charges) under the Rockport made under these contracts were $91 million in 2004, agreement amounted to $63 million, $66 million and

$113 million in 2003 and $145 million in 2002.

$59 million for 2004, 2003 and 2002, respectively.

On December 2, 2004, PEF entered into precedent and PEC executed two long-term agreements for the related agreements with Southern Natural Gas Company purchase of power from Broad River LLC's Broad River (SNG), Florida Gas Transmission Company (FGT), and BG facility. One agreement provides for the purchase of LNG Services, LLC for the supply of natural gas and approximately 500 MW of capacity through 2021 with an associated firm pipeline transportation to augment PEF's original minimum annual payment of approximately gas supply needs for the period from May 1, 2007, to

$16 million, primarily representing capital-related April 30, 2027. The total cost to PEF associated with the capacity costs. The second agreement provided for the agreements is approximately $3.3 billion. The transactions 101

V Notes to Consolidated Financial Statements are subjectto several conditions precedent, which include payments are approximately $26 million for 2005 through obtaining the Florida Public Service Commission's 2007. The Company has the right in the related agreements approval of the agreements, the completion and and their amendments that allow the Company to escrow commencement of operation of the necessary related those payments if certain conditions in the agreements are expansions to SNG's and FGTs respective natural gas met The Company has exercised that right and retained pipeline systems, and other standard closing conditions. 2004 and 2003 royalty payments of approximately$42 million Due to the conditions precedent in the agreements, the and $48 million, respectively, pending the establishment of estimated costs associated with these agreements are not the necessary escrow accounts. Once established, those included in the contractual cash obligations table above. funds will be placed into escrow.

CONSTRUCTION OBLIGATIONS During 2004 Progress Energy made the first installment of The Company has purchase obligations related to various $10 million for a contract dispute. The installments for capital construction projects. Total payments under 2005 and 2006, respectively, are $16 million and $17 million these contracts were $102 million, $158 million and (See Note 20).

$143 million for 2004, 2003 and 2002, respectively.

C. Leases OTHER PURCHASE OBLIGATIONS The Company leases office buildings, computer equipment, The Company has entered into various other contractual vehicles, railcars and other property and equipment with obligations primarily related to service contracts for various terms and expiration dates. Some rental payments operational services entered into by PESC, a PVI parts for transportation equipment include minimum rentals plus and services contract, and a PEF service agreement contingent rentals based on mileage. These contingent related to the Hines Energy Complex. Payments under rentals are not significant. Rent expense under operating these agreements were $69 million, $31 million and $420 leases totaled $65 million, $60 million and $71 million for million for 2004, 2003 and 2002, respectively. 2004, 2003 and 2002, respectively. Purchased power expense under agreements classified as operating leases On December 31, 2002, PEC and PVI entered into a were approximately$24 million in 2004 and S5 million in2003.

contractual commitment to purchase at least $13 million and $4 million, respectively, of capital parts by Assets recorded under capital leases at December 31 December31, 2010. During 2004 and 2003, no capital parts consist of:

have been purchased under this contract (inmillions) 2004 2003 Buildings $30 $30 B. Other Commitments Equipment and other 2 3 The Company has certain future commitments related to Less: Accumulated amortization (11 1 (10) four synthetic fuel facilities purchased that provide for $21 $23 contingent payments (royalties). The related agreements and their amendments require the payment of minimum Minimum annual payments, excluding executory costs annual royalties of approximately $7 million for each plant such as property taxes, insurance and maintenance, under through 2007. The Company recorded a liability (included in long-term noncancelable leases at December 31,2004, are:

other liabilities and deferred credits on the Consolidated Capital Operating Balance Sheets) and a deferred asset (included in other (inmillions) Leases Leases assets and deferred debits in the Consolidated Balance $4 $66 2005 Sheets), each of approximately $73 million and $94 million at 2006 4 55 December 31, 2004 and 2003, respectively, representing the minimum amounts due through 2007, discounted at 6.05%. 2007 4 58 At December31,2004 and 2003,the portions of the assetand 2008 4 58 liability recorded that were classified as current were 2009 3 54 approximately $26 million. The deferred asset will be Thereafter 31 307 amortized to expense each year as synthetic fuel sales are $50 $598 made. The maximum amounts payable under these Less amount representing imputed interest (21) agreements remain unchanged. Actual amounts paid under Present value of net minimum lease payments these agreements were none in 2004, $2million in 2003 and under capital leases $29 S51 million in 2002. Future expected minimum royalty 102

Progress Energy Annual Report 2004 In 2003, the Company entered into a new operating lease In connection with the sale of partnership interests in for a building, for which minimum annual rental Colona (See Note 4B), Progress Fuels indemnified the payments are included in the table above. The lease buyers against any claims related to Colona resulting terms provide for no rental payments during the last from violations of any environmental laws. Although the 15 years of the lease, during which period S53 million of terms of the agreement provide for no limitation to the rental expense will be recorded in the Consolidated maximum potential future payments under the Statements of Income. indemnification, the Company has estimated that the maximum total of such payments would not be material.

The Company, excluding PEC and PEF, is also a lessor of land, buildings and other types of properties it owns E. Claims and Uncertainties under operating leases with various terms and expiration OTHER CONTINGENCIES dates. The leased buildings are depreciated under the same terms as other buildings included in diversified 1. Pursuant to the Nuclear Waste Policy Act of 1982, the business property. Minimum rentals receivable under predecessors to PEF and PEC entered into contracts with noncancelable leases for 2005 through 2009 are the U.S. Department of Energy (DOE) under which the approximately $32 million, $22 million, $14 million, DOE agreed to begin taking spent nuclear fuel by no later

$9 million and $6 million, respectively, with $17 million than January 31, 1998. All similarly situated utilities were receivable thereafter. Rents received under these required to sign the same standard contract operating leases totaled $63 million, $46 million and

$53 million for 2004, 2003 and 2002, respectively. DOE failed to begin taking spent nuclear fuel by January 31, 1998. In January 2004, PEC and PEF filed a PEC is the lessor of electric poles, streetlights and other complaint in the United States Court of Federal Claims facilities. Minimum rentals under noncancelable leases against the DOE, claiming that the DOE breached the are $9 million for 2005 and none thereafter. Rents Standard Contract for Disposal of Spent Nuclear Fuel received totaled $32 million, S31 million and $28 million for (SNF) by failing to accept SNF from various Progress 2004, 2003 and 2002, respectively. Energy facilities on or before January 31, 1998. Damages due to DOE's breach will likely exceed $100 million.

PEF is the lessor of electric poles, streetlights and other Approximately 60 cases involving the Government's facilities. Rents received are based on a fixed minimum actions in connection with spent nuclear fuel are rental where price varies by type of equipment and totaled currently pending in the Court of Federal Claims.

$63 million, $56 million and $52 million for 2004, 2003 and 2002, respectively. Minimum rentals receivable (excluding DOE and the PEC/PEF parties have agreed to a stay of the streetlights) under noncancelable leases for 2005 is lawsuit, including discovery. The parties agreed to, and the

$5 million, for 2006 through 2009 $1 million, and trial court entered, a stay of proceedings, in order to allow

$8 million thereafter. Streetlight rentals were $40 million, for possible efficiencies due to the resolution of legal and

$38 million and $34 million for 2004, 2003 and 2002 factual issues in previously filed cases in which similar respectively. Future streetlight rentals would approximate claims are being pursued by other plaintiffs. These issues 2004 revenues. may include, among others, so-called 'rate issues,' or the minimum mandatory schedule for the acceptance of SNF D. Guarantees and high level waste (HLW) by which the Governmentwas contractually obligated to accept contract holders' SNF To facilitate commercial transactions of the Company's and/or HLW, and issues regarding recovery of damages subsidiaries, Progress Energy and certain wholly owned under a partial breach of contract theory that will be subsidiaries enter into agreements providing future alleged to occur in the future. These issues have been or financial or performance assurances to third parties are expected to be presented inthe trials that are currently (See Note 19). scheduled to occur during 2005. Resolution of these issues in other cases could facilitate agreements by the parties in At December 31, 2004, the Company had issued the PEC/PEF lawsuit, or at a minimum, inform the Court of guarantees on behalf of third parties with an estimated decisions reached by other courts if they remain maximum exposure of approximately $10 million. These contested and require resolution in this case. The trial guarantees support synthetic fuel operations. At court has continued this stay until June 24, 2005.

December 31, 2004, management does not believe conditions are likely for significant performance under these agreements.

103

V Notes to Consolidated Financial Statements With certain modifications and additional approval by the PEC initiated a lawsuit seeking a declaratory judgment NRC, including the installation of onsite dry storage that the termination was lawful. DMT counterclaimed, facilities at Robinson and Brunswick, PEC's spent nuclear stating the termination was a breach of contract and an fuel storage facilities will be sufficient to provide storage unfair and deceptive trade practice. On March 23, 2004, space for spent fuel generated on PEC's system through the United States District Court for the Eastern District of the expiration of the operating licenses for all of PEC's North Carolina ruled that PEC was liable for breach of nuclear generating units. contract, but ruled against DMT on its unfair and deceptive trade practices claim. On April 6,2004, the Court With certain modifications and additional approval by the entered a judgment against PEC in the amount of NRC, including the installation of onsite dry storage approximately $10 million. The Court did not rule on DMT's facilities at PEFs nuclear unit, Crystal River Unit No. 3 request under the contract for pending legal costs.

(CR3), PEFs spent nuclear fuel storage facilities will be sufficient to provide storage space for spent fuel On May 4,2004, PEC authorized its outside counsel to file generated on PEFs system through the expiration of the a notice of appeal of the April 6,2004, judgment, and on operating license for CR3. May 7, 2004, the notice of appeal was filed with the United States Court of Appeals for the Fourth Circuit. On In July 2002, Congress passed an override resolution to June 8,2004, DMT filed a motion to dismiss the appeal on Nevada's veto of DOE's proposal to locate a permanent the ground that PEC's notice of appeal should have been underground nuclear waste storage facility at Yucca filed on or before May 6,2004. On June 16,2004, PEC filed Mountain, Nevada. In January 2003, the State of Nevada, a motion with the trial court requesting an extension of Clark County, Nevada, and the City of Las Vegas petitioned the deadline for the filing of the notice of appeal. By order the U.S. Court of Appeals forthe District of Columbia Circuit dated September 10, 2004, the trial court denied the for review of the Congressional override resolution. These extension request. On September 15, 2004, PEC filed a same parties also challenged EPA's radiation standards for notice of appeal of the September 10, 2004, order, and by Yucca Mountain. On July 9, 2004, the Court rejected the order dated September 29, 2004, the appellate court challenge to the constitutionality of the resolution approving consolidated the first and second appeals. DMT's motion Yucca Mountain, but ruled that the EPA was wrong to set a to dismiss the first appeal remains pending.

10,000-year compliance period in the radiation protection standard. EPA is currently reworking the standard but has The consolidated appeal has been fully briefed, and the court not stated when the work will be complete. DOE originally of appeals has indicated that it will hear arguments which planned to submit a license application to the NRC to tentatively have been scheduled for the week of May 23,2005.

construct the Yucca Mountain facility by the end of 2004.

However, in November 2004, DOE announced it would not Inthe first quarter of 2004, PEC recorded a liability for the submit the license application until mid-2005 or later. Also in judgment of approximately S10 million and a regulatory November 2004, Congressional negotiators approved asset for the probable recovery through its fuel

$577 million for fiscal year 2005 for the Yucca Mountain adjustment clause in the first quarter of 2004. The project approximately $300 million less than requested by Company cannot predict the outcome of this matter.

DOE but approximately the same as approved in 2004. The DOE continues to state it plans to begin operation of the 3. On February 1, 2002, the Company filed a complaint repository at Yucca Mountain in 2010. PEC and PEF cannot with the Surface Transportation Board (STB) challenging predict the outcome of this matter. the rates charged by Norfolk Southern Railway Company (Norfolk Southern) for coal transportation to

2. In2001, PEC entered into a contract to purchase coal certain generating plants. In a decision dated from Dynegy Marketing and Trade (DMT). After DMT December 23, 2003, the STB found that the rates were experienced financial difficulties, including credit unreasonable, awarded reparations and prescribed ratings downgrades by certain credit reporting maximum rates. Both parties petitioned the STB for agencies, PEC requested credit enhancements in reconsideration of the December 23, 2003 decision. On accordance with the terms of the coal purchase October 20, 2004, the STB reconsidered its agreement in July 2002. When DMT did not offer credit December 23, 2003 decision and concluded that the enhancements, as required by a provision in the rates charged by Norfolk Southern were not contract, PEC terminated the contract in July 2002. unreasonable. Because the Company paid the maximum rates prescribed by the STB in its December 23, 2003 decision for several months during 2004, which were 104

Progress Energy Annual Report 2004 less than the rates ultimately found to be reasonable, the tax credits. Also, $7million has not been recognized due STB ordered the Company to pay to Norfolk Southern the to the decrease in tax liability resulting from expenses difference between the rate levels plus interest. incurred for the 2004 hurricane damage. The current Section 29 tax credit program expires at the end of 2007.

The Company subsequently filed a petition with the STB to phase in the new rates over a period of time, and filed a IMPACT OF HURRICANES notice of appeal withthe U.S. Court of Appealsforthe D.C. For the year ended December 31, 2004, the Company's Circuit Pursuant to an order issued by the STB on synthetic fuel facilities sold 8.3 million tons of synthetic January6,2005,the phasing proceeding will proceed on a fuel and the Company recorded $215 million of Section 29 schedule that appears likely to produce an STB decision tax credits. The amount of synthetic fuel sold and tax before the end of 2005. On January 12, 2005, the STB filed credits recorded in 2004 was impacted by hurricane a Motion to Dismiss the Company's appeal on the grounds costs that reduced the Company's projected 2004 regular that its October 20, 2004, order is not "final' until the tax liability.

Company's phasing application has been decided.

For the nine months ended September 30, 2004, the As of December 31, 2004, the Company has accrued a Company's synthetic fuel facilities sold 7.7 million tons of liability of $42 million, of which $23 million represents synthetic fuel, which generated an estimated $204 million reparations previously remitted to PEC by Norfolk of Section 29 tax credits. Due to the anticipated decrease Southern that are now subject to refund. Of the remaining in the Company's tax liability as a result of expenses

$19 million, $17 million has been recorded as deferred incurred for the 2004 hurricane damage, the Company fuel cost on the Consolidated Balance Sheet, while the estimated that it would be able to use in 2004, or carry remaining $2million attributable to wholesale customers forward to future years, onlyS125 million of these Section has been charged to fuel used in electric generation on 29 tax credits at September 30, 2004. As a result, the the Consolidated Statements of Income. Company recorded a charge of $79 million related to Section 29 tax credits at September 30, 2004.

The Company cannot predict the outcome of this matter.

On November 2,2004, PEF filed a petition with the FPSC to

4. The Company, through its subsidiaries, is a majority recover $252 million of storm costs plus interest from owner in five entities and a minority owner in one entity customers over a two-year period. Based on a that owns facilities that produce synthetic fuel as defined reasonable expectation at December 31, 2004, that the under the Internal Revenue Code (Code). The production FPSC will grant the requested recovery of the storm and sale of the synthetic fuel from these facilities qualify costs, the Company's loss from the casualty is less than for tax credits under Section 29 if certain requirements originally anticipated. As of December 31, 2004, the are satisfied, including a requirement that the synthetic Company estimates that it will be able to use in 2004, or fuel differs significantly in chemical composition from the carry forward to future years, S215 million of these coal used to produce such synthetic fuel and thatthe fuel Section 29 tax credits. Therefore, the Company recorded was produced from a facility that was placed in service tax credits of $90 million for the quarter ended December before July 1,1998. The amount of Section 29 credits that 31, 2004, which the Company now anticipates can be the Company is allowed to claim in any calendar year is used. For the year ended December 31, 2004, the limited by the amount of the Company's regular federal Company's synthetic fuel facilities sold 8.3 million tons of income tax liability. Synthetic fuel tax credit amounts synthetic fuel, which generated an estimated $222 million allowed but not utilized are carried forward indefinitely of Section 29 tax credits. As of December 31, 2004, the as deferred alternative minimum tax credits. All entities Company anticipates that approximately $7 million of tax have received PLRs from the IRS with respect to their credits related to synthetic fuel sold during the year could synthetic fuel operations. However, these PLRs do not not be used and have not been recognized.

address the placed-in-service date determination. The PLRs do not limit the production on which synthetic fuel The Company believes its right to recover storm costs is credits may be claimed. Total Section 29 credits well established; however, the Company cannot predict generated to date (including those generated by FPC the timing or outcome of this matter. If the FPSC should priorto its acquisition bythe Company) are approximately deny PEF's petition for the recovery of storm costs in

$1.5 billion, of which $713 million has been used to offset 2005, there could be a material impact on the amount of regular federal income tax liability and $745 million is 2005 synthetic fuels production and results of operations.

being carried forward as deferred alternative minimum 105

V Notes to Consolidated Financial Statements IRS PROCEEDINGS team's factual findings and believes that the Earthco facilities were placed in service before July 1,1998. The In September 2002, all of Progress Energy's majority- Company also believes that the report applies an owned synthetic fuel entities were accepted into the IRS's inappropriate legal standard concerning what constitutes Pre-Filing Agreement (PFA) program. The PFA program "placed in service.' The Company intends to contest the allows taxpayers to voluntarily accelerate the IRS exam field auditors' findings and their proposed disallowance of process in order to seek resolution of specific issues.

the tax credits.

In February 2004, subsidiaries of the Company finalized Because of the disagreement between the Company and execution of the Colona Closing Agreement with the IRS the field auditors as to the proper legal standard to apply, concerning their Colona synthetic fuel facilities. The the Company believes that it is appropriate and helpful to Colona Closing Agreement provided that the Colona have this issue reviewed by the National Office of the facilities were placed in service before July 1,1998, which IRS, just as the National Office reviewed the issues is one of the qualification requirements for tax credits involving chemical change. Therefore, the Company is under Section 29. The Colona Closing Agreement further asking the National Office to clarify the legal standard provides that the fuel produced by the Colona facilities in and has initiated this process with the National Office.

2001 is a 'qualified fuel for purposes of the Section 29 tax The Company believes that the appeals process, credits. This action concluded the PFA program with including proceedings before the National Office, could respect to Colona. take up to two years to complete; however, it cannot control the actual timing of resolution and cannot predict In July 2004, Progress Energy was notified that the IRS the outcome of this matter.

field auditors anticipated taking an adverse position regarding the placed-in-service date of the Company's In management's opinion, the Company is complying with four Earthco synthetic fuel facilities. Due to the auditors' all the necessary requirements to be allowed such credits position, the IRS decided to exercise its right to withdraw under Section 29, and, although it cannot provide certainty, from the PFA program with Progress Energy. With the it believes that it will prevail in these matters. Accordingly, IRS's withdrawal from the PFA program, the review of while the Company adjusted its synthetic fuel production Progress Energy's Earthco facilities is back on the normal for 2004 in response to the effects of expenses incurred procedural audit path of the Company's tax returns. due to the hurricane damage and its impact on 2004 tax Through December 31, 2004, the Company, on a liability, it has no current plans to alter its synthetic fuel consolidated basis, has used or carried forward production schedule for future years as a result of the IRS approximately $1.0 billion of tax credits generated by field auditors' report However, should the Company fail to Earthco facilities. If these credits were disallowed, the prevail inthese matters, there could be material liability for Company's one-time exposure for cash tax payments previously taken Section 29 tax credits, with a material would be $294 million (excluding interest), and earnings adverse impact on earnings and cash flows.

and equity would be reduced by approximately

$1.0 billion, excluding interest. Progress Energy's PROPOSED ACCOUNTING RULES amended $1.13 billion credit facility includes a covenant FOR UNCERTAIN TAX POSITIONS that limits the maximum debt-to-total capital ratio to 68%.

This ratio includes other forms of indebtedness such as In July 2004, the FASB stated that it plans to issue an guarantees issued by PGN, letters of credit and capital exposure draft of a proposed interpretation of SFAS No.

leases. As of December 31, 2004, the Company's debt-to- 109, Accounting for Income Taxes' (SFAS No. 109), that total capital ratio was 60.7% based on the credit would address the accounting for uncertain tax positions.

agreement definition for this ratio. The impact on this ratio The FASB has indicated that the interpretation would of reversing approximately $1.0 billion of tax credits and require that uncertain tax benefits be probable of being paying $294 million for taxes would be to increase the sustained in order to record such benefits in the financial ratio to 65.7%. statements. The exposure draft is expected to be issued in the first quarter of 2005. The Company cannot predict what On October 29, 2004, Progress Energy received the IRS actions the FASB will take or how any such actions might field auditors' report concluding that the Earthco facilities ultimately affectthe Company's financial position or results had not been placed in service before July 1, 1998, and of operations, but such changes could have a material thatthe tax credits generated by those facilities should be impact on the Company's evaluation and recognition of disallowed. The Company disagrees with the field audit Section 29 tax credits.

106

Progress Energy Annual Report 2004 PERMANENT SUBCOMMITTEE If the Annual Average Price falls between the Threshold Price and the Phase Out Price for a year, the amount by In October 2003, the United States Senate Permanent which Section 29 tax credits are reduced will depend on Subcommittee on Investigations began a general where the Average Annual Price falls inthat continuum. For investigation concerning synthetic fuel tax credits example, for 2003, if the Annual Average Price had been claimed under Section 29. The investigation is examining

$56.54 per barrel, there would have been a 50% reduction the utilization of the credits,the nature of the technologies in the amount of Section 29 tax credits for thatyear.

and fuels created, the use of the synthetic fuel and other aspects of Section 29 and is not specific to the Company's The Secretary of the Treasury calculates the Annual synthetic fuel operations. Progress Energy is providing Average Price based on the Domestic Crude Oil First information in connection with this investigation. The Purchases Prices published by the Energy Information Company cannot predict the outcome of this matter.

Agency (EIA). Because the EIA publishes its information on a three-month lag, the Secretary of the Treasury SALE OF PARTNERSHIP INTEREST finalizes its calculations three months after the year in In June 2004, the Company, through its subsidiary, question ends. Thus, the Annual Average Price for Progress Fuels, sold, in two transactions, a combined calendar year 2003 was published in April 2004.

49.8% partnership interest in Colona Synfuel Limited Partnership, LLLP, one of its synthetic fuel facilities. Although the official notice for 2004 is not expected to be Substantially all proceeds from the sales will be published until April 2005, the Company does not believe received over time, which is typical of such sales in the that the Annual Average Price for 2004 will reach the industry. Gain from the sales will be recognized on a cost Threshold Price for 2004. Consequently, the Company recovery basis. The Company's book value of the does not expect the amount of its 2004 Section 29 tax interests sold totaled approximately $5 million. The credits to be adversely affected by oil prices.

company received total gross proceeds of $10 million in 2004. Based on projected production and tax credit The Company cannot predict with any certainty the levels, the Company anticipates receiving approximately Annual Average Price for 2005 or beyond. Therefore, it

$24 million in 2005, approximately $31 million in 2006, cannot predict whether the price of oil will have a approximately $32 million in 2007 and approximately material effect on its synthetic fuel business after 2004.

$8 million through the second quarter of 2008. In the However, if during 2005 through 2007, oil prices remain at event that the synthetic fuel tax credits from the Colona historically high levels or increase, the Company's facility are reduced, including an increase in the price of synthetic fuel business may be adversely affected for oil that could limit or eliminate synthetic fuel tax credits, those years, and, depending on the magnitude of such the amount of proceeds realized from the sale could be increases in oil prices, the adverse affectforthose years significantly impacted. could be material and could have an impact on the Company's synthetic fuel results of operations and IMPACT OF CRUDE OIL PRICES production plans.

Although the Internal Revenue Code Section 29 tax credit program is expected to continue through 2007, recent 5.The Company and its subsidiaries are involved in various unprecedented and unanticipated increases in the price litigation matters in the ordinary course of business, some of oil could limit the amount of those credits or eliminate of which involve substantial amounts. Where appropriate, them altogether for one or more of the years following accruals and disclosures have been made in accordance 2004. This possibility is due to a provision of Section 29 with SFAS No. 5, 'Accounting for Contingencies,' to that provides that if the average wellhead price per barrel provide for such matters. In the opinion of management, for unregulated domestic crude oil for the year (the the final disposition of pending litigation would not have a

'Annual Average Price' exceeds a certain threshold material adverse effect on the Company's consolidated value (the Threshold Price"), the amount of Section 29 results of operations or financial position.

tax credits are reduced for that year. Also, if the Annual Average Price increases high enough (the 'Phase Out Price"), the Section 29 tax credits are eliminated for that year. For 2003, the Threshold Price was $50.14 per barrel and the Phase Out Price was $62.94 per barrel. The Threshold Price and the Phase Out Price are adjusted annually for inflation.

107

V Notes to Consolidated Financial Statements

24. SUBSEQUENT EVENTS Cost-Management Initiative Sale of Progress Rail On February 28, 2005, as part of a previously announced cost-management initiative, the executive officers of the On February 18, 2005, the Company announced it has Company approved a workforce restructuring. The entered into a definitive agreement to sell Progress Rail to restructuring will result in a reduction of approximately One Equity Partners LLC, a private equity firm unit of J.P. 450 positions and is expected to be completed in Morgan Chase & Co. Gross cash proceeds from the September 2005. The cost-management initiative is transaction will be $405 million, subject to working capital designed to permanently reduce by S75 million to adjustments.The sale isexpected to close by mid-2005, and $100 million the projected growth in the Company's annual issubject to various closing conditions customary to such operation and maintenance expenses bythe end of 2007. In transactions. Proceeds from the sale are expected to be addition to the workforce restructuring, the cost-used to reduce debt The Company expects to report management initiative includes a voluntary enhanced Progress Rail as a discontinued operation in the first retirement program.

quarter of 2005. The carrying amounts for the assets and liabilities of the discontinued operations disposal group In connection with the cost-management initiative, the included in the Consolidated Balance Sheets as of Company expects to incur one-time pre-tax charges of December 31, are as follows: approximately $130 million. Approximately $30 million of (inmillions) 2004 2003 that amount relates to payments for severance benefits, Total current assets $378 $373 and will be recognized in the first quarter of 2005 and paid Total property, plant & equipment (net) 173 151 over time. The remaining approximately $100 million will Total other assets 40 77 be recognized in the second quarter of 2005 and relates Total current liabilities 156 114 primarilyto postretirement benefits thatwill be paid over Total long-term liabilities 3 3 time to those eligible employees who elect to participate in the voluntary enhanced retirement program.

Total capitalization 432 484 Approximately 3,500 of the Company's 15,700 employees are eligible to participate in the voluntary enhanced retirement program.The total cost-management initiative charges could change significantly depending upon how many eligible employees elect early retirement under the voluntary enhanced retirement program and the salary, service years and age of such employees.

108

Selected Consolidated Financial Data (Unaudited) Progress Energy Annual Report 2004 CONSOLIDATED QUARTERLY FINANCIAL DATA (UNAUDITED)

Summarized quarterly financial data is as follows:

First Second Third Fourth (inmillions except per share data) Quarter Quarter Quarter Quarter Year ended December 31 2004 Operating revenues $2,245 $2Z408 S2.761 $2Z358 Operating income 296 305 584 291 Income from continuing operations before cumulative effect of changes inaccounting principles 108 153 303 189 Net income 108 154 303 194 Common stock data:

Basic earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.45 0.63 1.25 0.78 Net income 0.45 0.63 1.25 0.80 Diluted earnings per common share Income from continuing operations before cumulative effect of changes inaccounting principles 0.45 0.63 1.24 0.78 Net income 0.45 0.63 1.24 0.80 Dividends declared per common share 0.575 0.575 0.575 0.590 Market price per share - High 47.95 47.50 44.32 46.10

- Low 43.02 40.09 40.76 40.47 Year ended December 31, 2003 Operating revenues S2Z187 $2,050 S2,457 $2,047 Operating income 357 274 478 248 Income from continuing operations before cumulative effect of changes in accounting principles 207 154 337 113 Net income 219 157 318 88 Common stock data:

Basic earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.89 0.65 1.41 0.47 Net income 0.94 0.66 1.33 0.37 Diluted earnings per common share Income from continuing operations before cumulative effect of changes in accounting principles 0.89 0.65 1.39 0.47 Net income 0.94 0.66 1.31 0.37 Dividends declared per common share 0.560 0.560 0.560 0.575 Market price per share - High 46.10 48.00 45.15 46.00

- Low 37.45 38.99 39.60 41.60 In the opinion of management, all adjustments necessary Section 29 tax credits being recorded (See Note 23E).

to fairly present amounts shown for interim periods have Third quarter 2004 includes reversal of $79 million of been made. Results of operations for an interim period Section 29 tax credits (See Note 23E). Second quarter may not give a true indication of results for the year. The 2004 includes the settlement of a civil proceeding related 2003 amounts were restated for the cessation of to SRS of $43 million ($29 million after-tax). Fourth quarter reporting results for portions of the Fuels' segment 2003 includes impairments related to Kentucky May and operations one month in arrears (See Note 18) and for Affordable Housing investment of $38 million ($24 million discontinued operations (See Note 4C). Fourth quarter after-tax) (See Note 10). Fourth quarter 2003 includes a 2004 includes a $31 million after-tax gain on sale of cumulative effect for DIG Issue 20 of $38 million natural gas assets (See Note 4A) and $90 million of ($23 million after-tax) (See Note 18).

109

V Selected Consolidated Financial and Operating Data (Unaudited)

SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA (UNAUDITED)

(inrmillionsexceptpersharedataJ 2004 2003 2002 2001 2000 Results of Operationsla)

Operating revenues $9,772 $8,741 $8,091 $8,129 $3,769 Net income from continuing operations before cumulative effect 753 811 552 541 478 Net income $759 $782 S528 $542 $478 Balance Sheet Data at Year-end Total assets(b) $25,993 $26,093 $24,272 $23,701 $22,875 Capitalization:

Common stock equity $7,633 S7,444 $6,677 $6,004 $5,424 Preferred stock-redemption not required 93 93 93 93 93 Minority interest 36 30 18 12 -

Long-term debt netdc) 9,521 9,934 9,747 8,619 4,904 Current portion of long-term debt 349 868 275 688 184 Short-term obligations 684 4 695 942 4,959 Total Capitalization and Total Debt $18,316 $18,373 $17,505 $16,358 $15,564 Other Financial Data Return on average common stock equity (percent) 9.99 11.07 8.44 9.41 13.04 Ratio of earnings to fixed charges 2.26 1.97 1.48 1.52 3.36 Number of common shareholders of record 67,638 70,159 72,792 75,673 80,289 Book value per common share $3126 S30.94 $28.73 $28.20 $27.17 Basic earnings per common share Income from continuing operations $3.11 S3.42 $2.54 S2.64 $3.04 Net income $3.13 S3.30 $2.43 $2.65 $3.04 Diluted earnings per common share Income from continuing operations 3110 S3.40 $2.53 $2.63 $3.03 Net income S3.12 S3.28 $2.42 S2.64 $3.03 Dividends declared per common share $2.32 S2.26 $2.20 $2.14 $2.08 Energy Supply - Electric Utility (millions of kWh)la)

Generated Steam 50,782 51,501 49,734 48,732 31,132 Nuclear 30,445 30,576 30,126 27,301 23,857 Hydro 802 955 491 245 441 Combustion turbines/combined cycle 9.695 7,819 8,522 6,644 1,337 Purchased 13,466 13,848 14,305 14,469 5,724 Total energy, supply (Company share) 105.190 104,699 103,178 97,391 62,491 Joint-owner shareld) 5,395 5,213 5,258 4,886 4,505 Total System Energy Supply 110,585 109,912 108.436 102,277 66,996 (a)Results of operations and energy supply data includes information for Florida Progress Corporation since November 30,2000, the date of acquisition.

(b)All periods have been restated for the reclassification of cost at removal.

(c)Includes long-term debt to affiliated trust of $270 million at December 31,2004, and 2003.

Id)Amounts are net of Company's purchases from joint-owners.

110

Reconciliation of Ongoing Earnings per Share to Progress Energy Annual Report 2004 Reported GAAP Earnings per Share (Unaudited)

RECONCILIATION OF ONGOING EARNINGS suit Management does not believe this settlement charge PER SHARE TO REPORTED GAAP EARNINGS is indicative of the ongoing operations of the Company.

PER SHARE (UNAUDITED) Gain on Sale of Natural Gas Assets Progress Energy's management uses ongoing earnings InDecember2004,the Companyfinalizedthe sale of certain per share to evaluate the operations of the Company and gas-producing properties and related assets and to establish goals for management and employees.

recognized a gain. Management does not believe this gain Management believes this presentation is appropriate isrepresentative of the ongoing operations of the Company.

and enables investors to compare more accurately the Company's ongoing financial performance over the Cumulative Effect of Accounting Changes periods presented. Ongoing earnings as presented here may not be comparable to similarly titled measures used Progress Energy recorded the cumulative effect of by other companies. Reconciling adjustments from GAAP changes in accounting principles due to the adoption of earnings to ongoing earnings are as follows: new FASB accounting guidance. The impact to Progress Energy was due primarily to the new FASB guidance December31 2004 2003 2002 related to the accounting for certain contracts. Due to the Ongoing earnings per share $3.06 $3.56 $3.81 nonrecurring nature of the adjustment, management Contingent value obligation mark-to-market 0.04 (0.04) 0.13 believes it is not representative of the 2003 operations of NCNG discontinued operations 0.02 (0.03) 10.11) the Company.

SRS litigation settlement (0.12) - -

Gain on sale of natural gas assets 0.13 - - Impairments and One-Time Charges Cumulative effect of accounting changes - (0.09) -

During 2003, the Company recorded after-tax impairments Impairments and one-time charges - (0.10) (1.22) of its Affordable Housing portfolio and certain assets at Ice storm impact - - (0.08) the Kentucky May coal company. During 2002, the PEF retroactive revenue refund - - (0.10) Company committed to a divestiture plan for Railcar, Ltd.,

Reported GAAP earnings per share $3.13 $3.30 $2.43 and recorded an estimated loss on assets held for sale.

During 2002, the Company also recorded an after-tax impairment and one-time charge of Progress Telecom's Contingent Value Obligation (CVO) and Caronet's assets. Progress Energy also wrote off the Mark-to-Market remaining amount of its investment in Interpath.

In connection with the acquisition of Florida Progress Management does not believe these impairments and Corporation, Progress Energy issued 98.6 million CVOs. one-time charges are representative of the ongoing Each CVO represents the right to receive contingent operations of the Company.

payments based on after-tax cash flows above certain levels of four synthetic fuel facilities purchased by Ice Storm Impact subsidiaries of Florida Progress Corporation in October During 2002,the Company experienced a severe ice storm 1999. The CVOs are debt instruments and, under GAAP, are in the Carolinas that caused extensive damage to the valued at market value. Unrealized gains and losses from distribution system. Due to the extensive costs associated changes inmarketvalue are recognized inearnings. Since with the storm damage, management believes the changes in the market value of the CVOs do not affect the restoration costs are not representative of the 2002 Company's underlying obligation, management does not ongoing operations of Progress Energy Carolinas.

consider the adjustment acomponent of ongoing earnings.

PEF Retroactive Revenue Refund NCNG Discontinued Operations The one-time retroactive rate refund under the Progress The operations of NCNG are reported as discontinued Energy Florida rate settlementin March 2002 was related to operations due to its sale, and therefore management funds collected during the period between March 13, 2001, does not believe this activity is representative of the when the prior rate agreement in Florida expired, and ongoing operations of the Company. March 27, 2002, the date the parties entered into the settlement agreement Due to the nonrecurring nature of SRS Litigation Settlement the refund, management believes it is not representative InJune 2004, SRS, a subsidiary of the Company, reached of the 2002 operations of Progress Energy Florida.

and recorded achargefora settlementagreementin acivil 111

V Shareholder Information Notice of Annual Meeting Proxy material, including the annual report, can be electronically delivered to shareholders. Electronic Progress Energy's 2005 annual meeting of shareholders delivery provides immediate access to proxy material will be held on May 11, 2005, at 10 a.m. at the Hilton and allows Internet voting while saving printing and St. Petersburg, in St. Petersburg, Fla. A formal notice of mailing costs. To take advantage of electronic delivery of the meeting with a proxy statement will be mailed to proxy material, go to econsentcom/pgn and follow shareholders inearly April. the instructions.

Transfer Agent and Registrar Mailing Address We also offer online access to shareholder accounts. To Progress Energy, Inc. obtain online access to your shareholder account, go to c/o EquiServe Trust Company equiserve.com. If you have access to Progress Energy's 250 Royall Street annual report at your address, and do not wantto receive Canton, MA 02021 a copy for your shareholder account, please call our Toll-free phone number 1.866.290.4388 transfer agent, EquiServe, toll-free at 1.866.290.4388 to discontinue receiving annual reports by mail.

Shareholder Information and Inquiries Securities Analyst Inquiries Obtain information on your account 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day, seven days aweek by calling our stock transfer agent's Securities analysts, portfolio managers and representatives shareholder information line. This automated system of financial institutions seeking information about features Progress Energy's common stock closing price, Progress Energy should contact Robert F.Drennan Jr.,

dividend information, stock transfer information and manager, Investor Relations, at the corporate the option to speak with a shareholder services headquarters' address or 919.546.7474.

representative. Call toll-free 1.866.290.4388.

Additional Information You may direct other questions concerning stock Progress Energy files periodic reports with the Securities ownership to Progress Energy's Shareholder Relations and Exchange Commission that contain additional via e-mail at shareholder.relations~pgnmail.com or by information about the company. Copies are available to writing to the following address: shareholders upon written request to the company's treasurer at the corporate headquarters' address.

Progress Energy, Inc.

Shareholder Relations This annual report is submitted for shareholders' P.O. Box 1551 information. It is not intended for use in connection with Raleigh, NC 27602-1551 any sale or purchase of, or any offer or solicitation of offers to buy or sell, securities.

Stock Listings Progress Energy's common stock is listed and traded NYSE Certifications under the symbol PGN on the New York Stock Exchange Because Progress Energy's common stock is listed on in addition to regional stock exchanges across the the New York Stock Exchange ('NYSE'), our chief United States. executive officer is required to make, and he has made, an annual certification to the NYSE stating that he was Shareholder Programs not aware of any violation by us of the corporate Progress Energy offers the Progress Energy Investor Plus governance listing standards of the NYSE. Our chief Plan, a direct stock purchase and dividend reinvestment executive officer made his annual certification to that plan, and direct deposit of cash dividends to bank effect to the NYSE as of June 10, 2004. In addition, we accounts for the convenience of shareholders. For have filed, as exhibits to the Annual Report on Form 10-K, information on these programs, contact our transfer the certifications of our principal executive officer and agent at the above address or call them toll-free at principal financial officer required under Section 302 of 1.866.290.4388. the Sarbanes-Oxley Act of 2002 to be filed with the Securities and Exchange Commission regarding the quality of our public disclosure.

112

)2005 Progress Energy. Inc. SCC-1 12-05 03/05

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